Emera Inc (EMA) 2016 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Emera first-quarter 2016 conference call and webcast. After the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time.

Please note that this call is being recorded today, Tuesday, May 10, 2016, at 11 o'clock Atlantic time.

I would now like to turn the meeting over to your host for today's call, Scott LaFleur, Manager Investor Relations for Emera. Please go ahead, Mr. LaFleur.

Good morning, everyone, and thank you for joining us for our first-quarter conference call this morning. Joining me from Emera are Chris Huskilson, President and Chief Executive Officer; Greg Blunden, Chief Financial Officer; and other members of the management team.

Emera's first-quarter earnings release was distributed earlier via newswire, and the financial statements and management's discussion and analysis are available on our website at Emera.com. This morning, Chris will begin with a corporate update and Greg will provide an overview of the financial results. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts.

I will take a moment to advise you that this conference call will contain forward-looking information and statements with respect to Emera. Forward-looking statements involve significant risk, uncertainties, and assumptions. Certain material factors or assumptions have been applied and drawn in the conclusions contained in the forward-looking statements.

Generally, these factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations. Such risk factors or assumptions include, but are not limited to regulation, energy prices, general economic conditions, weather, derivatives and hedging, capital resources, loss of service area, licenses and permits, environment, insurance, labor relations, human resources and liquidity risk. A number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements. In addition, please note this conference is being widely circulated via live webcast.

And now, I will turn things over to Chris.

Thank you, Scott, and good morning, everyone.

Emera delivered adjusted net income of $120.2 million, or $0.81 per share, in Q1 of 2016, compared to $171.6 million, or $1.18 per share, in Q1 of 2015.

Adjusting net income to exclude costs related to the TECO Energy in the acquisition resulted in $137.7 million, or $0.93 per share. The variance from last year is primarily related to the warmer winter in the Northeast, which resulted in lower electricity sales in Nova Scotia Power and Emera Maine, as well as lower market prices at Emera Energy's New England gas plant.

Emera's operations have continued to perform well, as we have implemented our growth strategy, and our earnings and cash flow are on track to support our 8% annual dividend growth target through 2019. Greg will take you through the details of the quarterly results later in his remarks, but first, I want to touch on some key strategic highlights and milestones Emera reached in Q1 of 2016.

We continue to move through major milestones regarding the TECO Energy acquisition. In February, the Hart-Scott-Rodino waiting period expired. In March, the Committee On Foreign Investments In the United States completed its review of the transaction.

The only regulatory approval requirement now remaining is in New Mexico, where we continue to work through the important steps of the Public Regulation Commission's regulatory process, otherwise known as the PRC. As we announced last month, Emera along with TECO Energy, New Mexico Gas and interveners in the case filed an unopposed and uncontested settlement with the PRC. The settlement agreement is focused on growing the New Mexico economy and it prospects for New Mexico Gas's success in that economy.

It provides benefits to customers and communities across the state. Included in the settlement agreement, our commitments from Emera to honor the stipulations made by TECO in their 2014 acquisition of New Mexico Gas; invest in the expansion of New Mexico's natural gas infrastructure system to underserved communities; expand a natural gas pipeline to the Mexican border; and provide resources to support certain economic growth project and programs across the state.

On May 2, the New Mexico PRC's hearing examiner conducted the hearing for the transaction, which included testimony on the settlement agreement from myself and others from Emera, New Mexico Gas, and the staff of the PRC. I believe the hearing went well, and we look forward to the hearing examiner's report in the ultimate decision from the New Mexico PRC.

I continue to be excited about the TECO Energy acquisition and the future growth potential it represents. Our integration plans are progressing well, and as we move toward closing, which we still expect to take place in mid-2016, we continue to see 5% accretion and 2017, and growing to greater than 10% in 2019.

We look forward to welcoming 3700 dedicated new employees and serving 1.6 million new customers in Florida and New Mexico. On the Maritime Link Project, construction continues on all major elements. The first of the Horizontal Directional Drill's boreholes have been completed at Cape Rey, and we expect to have the second borehole completed by late May.

Manufacturing of the first of two submarine cables is underway in Japan, and the second cable is scheduled to be manufactured starting late Q2 in Norway. All other aspects of the project are under construction and progressing. We continue to have confidence that the project will be completed on budget and on schedule for completion in late 2017.

At Emera Energy, we managed a strong first quarter from our marketing and trading business, increasing its US margins slightly over 2015, despite the low absolute price and volatility of natural gas so far this year. This result reflected long-term hedges that were put in place in periods where stronger market conditions and increased volumes. Overall, market conditions in 2016 are materially softer than in the past few years, but Emera continues to build its business while maintaining its low-risk profile, and has become a supplier of choice to several large LDCs, as well as generators throughout New England.

The New England generation assets also performed well in a challenging market in Q1. Our portfolio realized a spark spread of $27 per megawatt hour, reflecting above-market hedges previously entered. This was significantly higher than overall markets spark spreads, which averaged less than $10 per megawatt hour for much of the quarter.

Looking to the summer, we have hedged approximately 25% of output from April to October, increasing to 40% from June to August, with spark spreads in the low to mid-teens, which is well above the five-year historical pricing average for most months. Winter of 2015/2016 spark spreads have returned to normal at some $15 per megawatt hour, well below the $51 and $35 per megawatt hour spark spreads we've enjoyed at Bridgeport in 2015 and 2016. It is not surprising on the heels of the warm winter just experienced. To date, we have hedged less than 10% of our November/December output at these levels.

In January, Emera Maine and Central Maine Power submitted a bid to the Clean Energy Request for Proposals to tri-state RFPs being conducted by utilities and state agencies in Connecticut, Massachusetts and Rhode Island. We are awaiting initial project selection and expect to hear some time before the end of July.

We believe that the MREI is the most cost-effective and technically straightforward option for meeting both the 2020 delivery timeframe and the energy requirements requested in the RFP. As a follow-on, we believe legislation to enable clean energy imports is likely in this session of the Massachusetts legislature, although the precise amounts and allocation of different types of generation is still the subject of debate. We look forward to the opportunity to participate.

At Nova Scotia Power, we exceeded our 2015 renewable energy target, and are confident that we will meet or exceed our 2020 target of 40%. We've been working hard to stabilize rates, while completing the most ambitious transition to renewable energy in Canada. Our commitment remains to provide stable and predictable rates for our customers. That is a occurring through our three-year rate stabilization submission that is currently before the Utility and Review Board. We are also looking forward to getting the Maritime Link in service, and becoming part of the energy loop that the Lower Churchill Project will create, and ultimately including Muskrat Falls hydro in the Nova Scotia energy mix.

Moving to the Caribbean, we completed our transaction to acquire all remaining outstanding shares of Emera Caribbean, Incorporated. This transaction streamlines the ownership structure of our assets in the Caribbean and facilitates our continued commitment to the region. Our strategy is to move away from primarily oil-based generation to more renewable clean energy sources with a focus on affordability and rate stability. In conclusion, 2016 remains an important and exciting year for Emera as the Company continues to progress and transform.

With that, I will turn things over to Greg, who will provide you with an overview of the financial results. Greg.

Thank you, Chris, and good morning, everyone.

You'll notice that this quarter's results are affected by a number of factors, including the TECO Energy acquisition, which will continue throughout 2016. The acquisition costs and the timing of the close will both have an effect on our ongoing financial results.

We will continue to provide clarity on these changes to help you better understand Emera's underlying business. Our earnings remain on track with expectations, and Emera's business performed as expected in the first quarter. Our consolidated net income in Q1 2016 was $44.3 million, or $0.30 per share.

When current year's results are normalized with $75.9 million of mark-to-market losses, first-quarter 2016 net income was $120.2 million, or $0.81 per share. When normalized from mark-to-market impacts, adjusted net income in the prior year was $171.6 million, or $1.18 per share. In Q1, 2016, Emera incurred TECO acquisition of financing costs of $17.5 million, or $0.12 per share. Adjusted EPS, removing the TECO acquisition costs, was $0.93 per share.

The decrease quarter over quarter was primarily due to several factors, including the lower expected contribution from the New England generating facilities, the effects of warmer weather at Nova Scotia Power and Emera Maine, the TECO Energy acquisition-elated costs, and the gain on the sale of Northeast Wind partnership in Q1 of 2015. I will begin our segmented results with Nova Scotia Power, which provided net income of $52.5 million in Q1 2016, compared to $68 million in Q1 of 2015.

The decrease was primarily related to lower electricity sales due to the warmer weather and increase [OMG] costs due to storm impacts. Emera Maine contributed $9.3 million to consolidate net income in Q1 2016, compared to $11.5 million for the same period last year. The decrease was primarily related to reduced sales caused by weather, reduced industrial load, increased storm costs, and the timely capital expenditures. The decrease was partially offset by increased rates and the effect of the stronger US dollar.

Emera Caribbean's net income increased 11% to $9.8 million in the first quarter 2016, primarily due to the impact of the stronger US dollar. Our pipeline segment contributed adjusted net income of $9.7 million in the quarter, consistent with last year.

Emera Energy's adjusted net income decreased $28.5 million to $47.9 million in Q1 2016, compared to the same period of last year. This expected decrease was primarily due to reduced contributions of the New England gas generating facilities, mainly due to lower hedge and market power prices in 2016, and the gain of the sale of Northeast Wind partnership in Q1 of 2015. The decrease was partially offset by the stronger US dollar and increased marketing and trading margin. Our corporate and other segment posted a $9-million adjusted net loss in Q1 2016, compared to a loss of $3 million in Q1 2015, the variance primarily due to $17.5 million in acquisition costs for TECO Energy, partially offset by higher equity earnings.

I will now move on to an update on the financing of the TECO acquisition. As Chris mentioned earlier, we're moving through the government and regulatory approvals with the final remaining regulatory approval required from the state of New Mexico. We are gaining confidence on the timing of the acquisition close in mid-2016, and the different components of the financing plan remain the same.

This includes common equity and available sources of cash of between $1.7 billion to $2.1 billion, which our CAD2.185 billion convertible debenture is expected to fulfill. We also have $0.8 billion to $1.2 billion in preferred equity or hybrid securities, and between $3.4 billion and $3.8 billion in debt that we expect to issue around the time of closing.

Our financing plan is progressing as planned and we look forward to working through the important remaining steps to close the TECO Energy acquisition. That's all for my update, and now we are happy to take any questions that you may have.

(Operator Instructions)

Linda Ezergailis, your line is open for TD Securities.

Thank you.

I have a question about your relationship with Nalcor and Muskrat Falls. I am wondering, we have read a lot in the media what your recent dialogue has been with them, if it has changed at all, and to the extent that there might be an opportunity to invest more in the expanded scope of the project, whether it be wires or generation, what factors would need to be in place for Emera to consider that or other scenarios?

Thank you, Linda.

First of all, I would say that we have had a positive working relationship with our partner Nalcor, and also with all the governments involved, Newfoundland, Nova Scotia, and the federal government. Those relationships have been going on now since 2010.

That has gone very well, nothing has really changed. We are at the same place, I would say, that we were originally, and we are continuing to proceed. Obviously, Nalcor now has a new CEO, and we're looking forward to working with Mr. Marshall, and we think that the relationship will continue.

Fundamentally, we have to look at it through the Maritime Link, and it is on time and on budget right now, and we're looking forward to that being in service in late 2017. Beyond that, I think that that is really where we are.

Okay. Thank you. I am wondering if you can also comment on some of the other financing needs you might have outside of TECO, to what extent might divestitures of less core investments be a part of how you're looking at the next couple of years?

I think, always, internal cash generation is an important part of how we are funding and financing our business. As you look at the business going forward, the internal cash generation is getting stronger all the time. That is a very good thing. Secondly, I think we have already told the market that we will be issuing somewhere between zero and $300 million of equity later this year, and that is certainly where we have been all along, and that whole combination is where we are.

Thank you.

Thank you, Linda.

Ben Pham of BMO. Your line is open.

Good morning, everybody.

Good morning, Ben

Good morning. Can you give us an update on your protection with respect to Lower Churchill with the capital costs rising or maybe even increasing further in the future? And how maybe the timing changes could impact you and your Maritime Link Project?

I think, first of all, one of the principles that we move forward with relative to that project is that the risk would be around the ability to control. We are not constructing either the generation facility or the transmission in Labrador or in Newfoundland, so we have not taken any risk relative to those projects at all.

We have taken risk, though, relative to the Maritime Link Project, because that is the project we are controlling, and in fact, we are building. And as we said today, I think we have been clear that our contingency -- we have been able to increase the value of our contingency from about 10% to 13% as we have gone through and contracted and are building the project, and so we still feel very good about where we are on that cost structure, and we are projecting that that project comes in on time and on budget.

That is really the only exposure we have from a cost perspective. As it relates to timing of the generation, Nalcor hasn't been clear about what they believe the timing is at this point. I think what we currently know is it is somewhat delayed.

So, we are planning around that, and if you look at what has been filed in the Nova Scotia rate stability plan, you will see that it does show a slight delay in the generation coming available, and I think that there are sensitivities being done around that within that process. Beyond that, we are looking forward to getting the Maritime Link in service, and getting the rest of the transmission in, because that will give us access to the energy loop, which will, I think, be helpful to the entire Atlantic region.

Okay. Thanks for that, Chris, and I was also wondering on Maritime Link, there was commentary late last year, your [dinner] about your Abengoa exposure, I just wanted to check in on that if anything has changed there. Is that still your contract, or was there any change in who you put in and maybe just a quick update on that.

I think there has not been any change in the status. Abengoa continues to be under creditor protection, they have been in that state since the latter part of last year. We continue to work with them, and our contract continues to be in force, and there are lots of contractual protections in there for us and our customers relative to working with a contractor that is under creditor protection, and we're working our way through it.

So, we are comfortable with where we are right now, really, that project is broken into five different components. Three of which are subcontracted, and those in the subcontractor is the PowerTel, who has been building projects across the country for some time. So, the overall project is split up that way.

Okay. Thanks, Chris. Thanks, everybody.

Andrew Kuske, Credit Suisse. Your line is open.

Thank you. Good morning.

This might be a question for Greg as it relates to NSPI and just when you look through the numbers, to what degree were the volumes, the follow-up in volumes really weather-related, and could you weather-normalize it to -- and then comparing that versus, say, actual fundamental demand destruction in the C&I group?

No. Andrew, great question. It is virtually all weather-related in the quarter. If you think of last year, I think we all recognize that Q1 last year was extremely cold, and we saw our load reflect that. It was just the opposite phenomenon in Q1 of this year. So we have not seen any demand destruction at all, in fact, with a weaker Canadian dollar and stability in prices, it seems to have firmed up quite nicely, and so I think you can pretty much attribute all of it to the unusual weather.

And, Andrew, Nova Scotia Power has filed a future forecast through the three-year period, 2017 through 2019, and right now they are showing modest growth in their requirements through that period.

Okay. That is very helpful.

If I may just ask a bit of a broader question. When you look at the New England power market in just a broad sense, and you think about your pipeline assets, your utility assets, and your power assets, and effectively the Emera Energy group around all of that, do you feel you have got a better view on intelligence, as it relates to maybe perspective power plant opportunities for capital investment acquisition when you just think about the businesses you have got in the region at this stage?

I mean, Andrew, there is no question that we have built a very nice portfolio in that marketplace. And that has allowed us to continue to serve customers in that market, I think, in a productive way. We continue to look forward and for opportunities to grow in that market, but we are also now continuing to start to look at other markets, and as you understand, with the closing of the transaction with TECO, we are also going to be doing business in New Mexico and in Florida.

We really are quite excited about entering those markets, we think there are growth opportunities certainly in both of those states. We think those companies are well-positioned to be able to grow in those markets, and so, you will see, somewhat more of our effort looking in the Southern part in the short-term. But we still will continue to operate in New England and to be very much mindful of the opportunities as they emerge.

If I may, just to follow up on that point. You are very close to closing off TECO, and the totality of the project, you're getting closer on the Nalcor-related transmission lines. When you look at your balance sheet in, let's just say, 2018, how do you think about your business mix at that point in time of regulated versus unregulated activities, what would be the proportionality you are really targeting at that point?

We are now continuing to target in the 75% to 85% regulated, and if you look at what is in front of the business, we have got about $6 billion over the next four years in front of the combined business. Of course, we are very respectful of the process that is going on in New Mexico right now.

We are working with the New Mexico PRC, and working towards their decision, and that's obviously the first step and the thing we have to focus on right now. But when we look at that combined Company, there is a nice growth profile that exists in the combined Company, and lots of projects that are already there in front of us. As I said, we are quite excited about that.

Our strategy continues to be all about taking higher carbon resources and moving them to lower carbon resources. That has worked well for us in the Northeast, specifically in Nova Scotia and around Atlantic Canada. I believe that there will be lots of opportunity in that area, whether we are talking about gas LDCs in New Mexico or Florida, or whether we are talking about EP Electric itself and its opportunity to continue to reduce carbon intensity, which is something its customers want to happen.

Very helpful. Thank you.

Thanks, Andrew.

Paul Lechem of CIBC. Your line is open.

Thank you. Good morning.

Chris, this may be following on from the commentary you made around looking for follow-on investments in the New England area. I was just wondering, given TransCanada out there looking to sell its northeast power assets, are any of those of interest to Emera at this point?

Paul, as you know we are always looking at opportunities and it really depends on value. From our perspective, we need to be focused on value, and also focused on the mix that we have in our Business.

All of these things get guided by our ability to manage the business, to raise capital, and to keep our Business at that 75% to 85% regulated, so those are really the parameters we look at. Again, we are always looking to find opportunities to create value for shareholders.

Okay. Going back to the Lower Churchill Project, and given the delays that we are seeing on Nalcor's side building up a generation part of the business, does that impact your ability to bid into any of these renewable power RFPs, especially if it's potential upcoming one from Massachusetts, given the uncertainty of timing of the Hydro clean power, is that -- that would, I presume, be part of the mix in terms of what you'd bid in, and so, does that impact your ability to fit into these RFPs?

Again, I do not think the timing is completely clear right now. I think that is something that Nalcor will update when they are ready to do that.

Obviously, we look forward to that update. But as it relates to those projects and the opportunity to supply energy, we've always looked at that, at this phase anyway, as being surplus energy that exists in the market and surpluses that exist from projects as they come on. Also, clean energy like wind, and so those are the projects that we think will be important to that.

The project we have proposed, which is the Atlantic Link, gives us the ability to collect energy from northern Maine, from New Brunswick, and that region, and also from Labrador and Newfoundland. And so, the flexibility that that project has to gather energy from all of those different locations, we believe, allows it to be probably the most flexible project that their regional will see. And so, with that flexibility, it does allow us to incorporate timings and new resources as they come available.

Got you. Thanks, Chris.

Thank you.

(Operator Instructions)

Robert Kwan, RBC Capital Markets. Your line is open.

Good morning.

Just starting on NSPI, you are not going to have a GRA for non-sales through 2019. I'm just wondering, does the 1.3% increase per year for the fuel side of things? Does that fully -- or is that expected to fully dispose of the FAM and fully recover the Maritime Link in low costs, as it relates -- not, obviously to fully recover the whole project, but just the cost in those specific years?

Yes, Robert. It's Scott speaking.

That is exactly right, so, that the 1.3% is expected to cover the expected fuel costs through that three-year period.

Which includes Maritime Link, Robert.

Okay. How does the rate freeze on the non-fuel square up with any unforeseen costs or capital investments in rate base?

Within that estimate, we have factored in within that three years our view is to our cost profile through that period. Obviously, we've got a long operating history, and we understand the variability of some of the cost inputs within that, and we fully factored that into that rate freeze through to 2019.

Is there wiggle room then in terms of contingency, or are there going to be explicit either deferral mechanisms or ability to have a rate rider for unforeseen costs?

If it is completely unforeseen and unpredictable, then I think there is a mechanism within the structure that allows us to deal with that, but for all of the majority and major issues, we forecast where we will be and we are comfortable that the business can manage through that period and do that on behalf of customers.

If I can finish up on Maine in two questions here. First being, just in the quarter, you had $3.4 million on the revenue side due to weather. If you think about it if you had normal weather, would that $3.4 million have dropped to the bottom line net of tax? And then, the second question on ROEs, did you release some of the reserves in the quarter back into revenues?

Your second question, Robert, no, we did not release any of the reserve back into the quarterly results, and the majority of the $3.4 million, if you tie it to the fact that it would've gone to the bottom line, there was some loss of industrial load that was not weather-related. But it would be probably --

We were down about 46 gigawatt hours and about 20 of that was industrial.

Maybe 40% of it, Robert, would have been lost in the industrial load in the balance [weather].

Thank you very much.

Thanks, Robert.

There are no further questions in queue at this time. I turn the call back over to the presenters.

Okay, well, thank you very much for your participation on the call today, and for your interest in Emera. Speaking of that interest, we are holding our AGM at the Design Exchange in Toronto next week, 2 PM on Tuesday, May 17.

We look forward to seeing you there for that meeting. Thank you all very much, and have a good day.

This concludes today's conference call. You may now disconnect.