Scott LaFleur - IR Chris Huskilson - President & CEO Greg Blunden - CFO

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

Good morning, ladies and gentlemen. 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 11:00 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 CEO; 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 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 remind you that this conference call will contain forward-looking information and statements with respect to Emera. Forward looking statements involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally. 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 risks. A number of factors could cause actual results, performance or achievement to differ materially from the results discussed or implied in the forward-looking statement. In addition, please note that this conference is being widely circulated via live webcast. 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 of Q1 in 2016 compared to $171.6 million or $1.18 in Q1 of 2015. Adjusting net income to exclude cost related the TECO energy acquisition resulted in $137.7 million or $0.93 per share. The variance from last year is primarily related to warmer winds, warmer winter in the north-east which resulted in lower electricity sales in Nova Scotia power and Emera Main. As well as lower market prices at Emera Energy's New England gas plant. Emera's operations has 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 major milestones regarding TECO energy acquisition. In February, Hart-Scott-Rodino waiting period expired. And in March the committee on foreign investments in US 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, 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 its prospects for New Mexico Gas a success in that economy. It provides benefits to customers and communities across the state. Included in the settlement agreement are commitments for Emera, honor the circulations made by TECO in their 2014 acquisition of New Mexico gas, invest in the expansion of New Mexico's natural gas infrastructure system to under-served communities, expand our natural gas pipeline to the Mexican border and provide resources to support through economic growth project and programs across the States. On May 2, the New Mexico's hearing examiner conducted a 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 hearing the examiner's report and 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 plan went well and as we move towards closing which we still expect to take place in May 2016. We continue to see 5% accretion in 2017 and growing to greater than 10% in 2019. We look forward to welcoming 3700 dedicated new employees and serving 1.6 million customers in Florida and United States. On the Maritime Link project construction continues on all major elements. The first of the horizontal directional drill [ph] have been completed at Cape Ray and we expect that to have the second by late May. Manufacturing of the first of the 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 with stronger market conditions and increased volume. Overall, market conditions in 2016 are materially softer than in the past few years. But Emera Energy continues to build its business while maintaining its low risk profile and has become a supplier of choice to several larges LDC as well as generators through New England. New England generation assets also performed well in a challenging market in Q1. Our portfolio realized the spark spread of $27 per megawatt hour above market hedges previously entered. This will significantly higher than overall market stock spreads which averaged less than $10 per megawatt hour. Looking to the summer we have hedged approximately 25% of load from April to October. Increasing to 40% from June to August with spreads in the low to mid-teens which is well above the 5 year historical pricing average for most months. Winter of 2015 and 2016 spark spreads have return to normal and so $15 per megawatt hour well below the $51 and $35 spark spreads we have enjoyed every quarter in 2015 and 2016. It's 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 Main and Central Maine power submitted a bid for Clean Energy Request Proposal, the tri-state RFP. 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 straight forward option for meeting both the 2020 delivery time frame and the energy requirements requested in the RFP. As a follow on we believe legislation to enable clean energy imports this session of the Massachusetts legislature, although the precise amounts of generation and allocation is still the subject of debate. We look forward to the opportunity to participate. At Nova Scotia Power we exceeded our 2016 renewable energy target and our confident that we will meet or exceed our 2020 target of 40%. We have been working hard to stabilize rates by completing the most ambitious transition to renewable energy in Canada. Our commitment remains to provide more stable and predictable rates for our customers. That is occurring through our 3 year rate stabilization submission that is currently before the utility interview board. We are also looking forward to getting the Maritime Link service and becoming part of the energy loop that 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 and the Corporate. 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 from primarily away from oil based generation to more renewable, clean energy sources with a focus on affordability and rate stability. In conclusions, 2016 remained an important year for Emera as the company continues to progress and transform. And 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 know that this quarter's results are affected by a number of factors including the TECO Energy acquisition which will continue throughout 2016. The acquisition cost and the timing of the close will both have an effect on our ongoing financial results plus we will continue to provide clarity on these changes to help you better understand the 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 results are normalized for the $75.9 million of mark to market losses, first quarter 2016 net income was $120.2 million or $0.87 per share. When normalized for mark to market impacts, adjusted net income in the prior year was $171.6 million or a $1.18 a share. In Q1, 2016 Emera incurred TECO acquisition and financing costs of $17.5 million or $0.12 per share. Adjusted EPS removing the TECO acquisition cost 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 generation facility, the effects of warmer weather at Nova Scotia Power and Emera Main, the TECO Energy acquisition relate costs and the gain of the sales of the north-east wind partnership in Q1 of 2015. I will begin our segment of results with Nova Scotia Power which provided a net income of $52.5 million in Q1 2016 compared to $68 million of 2015. The decrease was primarily related to lower electricity sales due to the warmer weather and increase cost due to the storm impact. Emera Main contributed $9.3 million to 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, pre storm costs and time to capital expenditures. The decrease was partially offset by increased rates and the effect of the stronger US dollar. Emera Care income increased 11% to $9.8 million in the first quarter of 2016 primarily due to the impact of the stronger US dollar. And our pipeline segment contributed adjusted income of $9.7 million in the quarter consistent with last year. Emera Energy's adjusted net income $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 from the New England's Gas Generating facility mainly due to lower hedged market prices in 2016 and the gain of the sales of North East wind partnership in the Q1 of 2015. Decrease was partially offset by the stronger US dollar and increase in 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 2015. The variance primarily due to a $17.5 million in acquisition costs for TECO Energy partially offset by higher equity earnings. I will now move on to update the financing of the TECO acquisition. As Chris mentioned earlier we are moving through the government and regulatory approvals and the final remaining regulatory approvals required from the sale of New Mexico. We are gaining confidence on the timing of the acquisition closed 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 $2.1 billion which our CAD$ 185 billion convertible debenture is expected to fulfill. We also have $0.8 billion to $1.2 billion in preferred equity or high pricing 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 you may have.

[Operator Instructions] Our first question comes from the line of Linda Ezergailis from TD Securities. Your line is open.

I have a question about your relationship with Now Core and Muskrat Falls. I am just wondering, we have read a lot in the media, about your recent dialogue with them, has it changed at all? And to the extent that there might be an opportunity to invest more in the expanded scope of project whether it be wire degeneration. What factors would need to be in place for Emera to consider that and other scenario?

Thank you Linda, first of all I have to say we have a very positive working relationship with Now Core and also with all governments involved from Nova Scotia and also the Federal government. Those relationships have been going on from 2010 and that's going very well. Nothing is really changed. We are at the same place I would say that we were originally and we are continuing to proceed. Obviously Now Core now has a new CEO and we are looking forward to working with Mr. Marshall. We think that the relationship will continue and fundamentally we have to look at it through the Maritime Link and it's on time and on budget right now and we are looking forward for that to be in budget by late 2017. Beyond that, that's really I think where we are.

Okay. Thank you and 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 are 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 so as you look at the business going forward the internal cash generation is getting stronger all the time so that is a very good thing. And secondly we have already told the markets that we will be issuing somewhere between 0 to $300 million of equity later this year. That's certainly where we have been all along and that whole combination is where we are.

Thank you.

Thanks, Linda.

And your question comes from the line of Ben Pham of BMO. Your line is open.

Hi, thanks good morning everybody. Can you give us an update on your protection in respect to lower Churchill with the capital costs rising or maybe even increasing in the near future and how may be the pending changes can impact you and your Maritime Link project?

Yes, first of all one of the principals we moved forward relative to that project was that the risk would be around the ability to control. And so we are not constructing either the generation or the transmission in Labrador or Newfoundland and so we haven't taken any risks relative to those projects at all. We have taken risks though to Maritime Link Project because that is the project we are controlling and in fact building and as we said today, we have been cleared that our contingency we have been able to increase, the value of our contingency from 10% to about 13% as we gone through and contracted and are building the project and we still feel very good about where we are on that cost structure and we are projecting the project comes in on time and on budget. And that's really the only exposure from a cost perspective. As it relates to timing of the generation, Now Core hasn't been clear of what they believe is the timing at this point. I think what we currently know is it's somewhat delayed and so we are planning around that and if you look at what's been filed in Nova Scotia re-stability plan you will see that it does show up slight delay in the generation coming available and I think there's sensitivities being done around that. Within that process, but beyond that we are looking to get the Maritime Link service and getting the rest of the transmission in, because that would give us access to the Energy loop which will be helpful to the entire Atlantic region.

Okay. Thanks for that Chris and I was also wondering on Maritime Link that there was some commentary late last year about your exposure, I just want to check if anything has changed there and regarding your contractor, was there any change in who you put in and maybe just a quick update on that?

Yes, there hasn't been any change in the status. Avengay [ph] continues to be under creditor protection. They have been in that state since last year. We continue to work with them and our contract continues to be enforced and there lots of contractual protections in there for us and customers relative to working with the contractor that is under creditor protection and we are working our way through it. So we are comfortable where we are right now and really that project is broken into 5 different components, 3 of which are sub-contracted and the sub-contractor is PowerTel who has been building projects across the country for some time and so the overall project is split up that way.

Okay. Thanks Chris, thanks everybody.

Okay. Thanks.

And your next question comes from the line of Andrew Kuske of Credit Suisse. Your line is open.

Thank you, good morning. This might be a question for Greg as it relates to NSPI. When you look through the numbers, to what degree do the volumes, follow up in volumes, really weather related and could you weather normalize it comparing that versus actual fundamental demand destruction in the C&I group?

No, Andrew. It's all weather related in the quarter. If you think of last quarter, I think we all recognized 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 haven't seen any demand destruction in fact with the weaker Canadian Dollar and instability in prices it seems to have firmed up quite nicely and so I attribute pretty much all of it to the unusual weather.

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

Okay. That's very helpful and if I may ask a bit of broader question. When you look at the New England power market in just the broad sense, you think about your pipeline assets, utility assets and your power assets and in fact with the Emera Energy Group around all of that, do you feel you have got a better view on just intelligence as it relates to maybe perspective power plants opportunities for capital investment acquisitions when you think about the business you got in the region at this stage?

Yes, Andrew there is no question that we have built a very nice portfolio in that market place and that's allowed us to continue to serve customers in that market in a productive way and so we continue to look forward and for opportunities to grow in the market or also continuing to start to look at other markets as you understand with the closing of the transaction with TECO, we are also going to be doing business in New Mexico and Florida and we really are quite excited about entering those markets. We think that there are growth opportunities in certainly both of those states. I 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 will still continue to operate in New England and to be very much mindful of the opportunities as they emerge.

And then just a follow up on those points. So you are very close to closing off TECO and totality of the project. You are getting closer on the Now Core related transmission lines and so when you look at your balance sheet of 2018, how you think about your business mix at that time of regulated versus unregulated activity. What would be the proportionality you are targeting at that point?

Yes, we are now continuing to target in the 75% to 85% regulated and if you look at what's in front of the business we have got about $6 billion over the next four years in front of the combined business and so of course we are very respectful of the process going on in New Mexico right now. We are working with the New Mexico PRC and working towards their decisions. And so that's how we see first half of things we need to have focus right now. But when we look at the 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. So we are quite excited about that. So our strategy continues to be all about taking a higher carbon resources and moving them to lower carbon resources. That has worked well for us in the north-east specifically in Nova Scotia and around Atlantic Canada. And I believe 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 electric itself and its opportunity to reduce carbon intensity which is something which customers want to happen.

You are very helpful, thank you.

Thanks Andrew.

And your next question comes from the line of Paul Lechem, CIBC. Your line is open.

Thank you, good morning. Chris this maybe following on from the commentary you made around looking for smaller investments in the New England area. I was just wondering given Trans-Canada out there looking to sell its North-east Power assets, are any of those of interest to Emera?

Paul as you know we are always looking at opportunities and they always depend on value from our perspective, we need to be focused on value. And also focused on the mix that we have in our business and so all of these things get guided by our ability to manage the business, raise capital and to keep our business assets 75% to 85% regulated. So those are really the parameters we look at and again we are always looking to find opportunities create value for shareholders.

Just going back to the Lord Churchill project back again and given the delays, we are seeing the Now Core building up the generation, does that impact your ability to bid in plenty of these renewable power RFPs, especially these potential upcoming ones from Massachusetts given the uncertainty of timing of Hydro clean power, that would be part of the mix you tend to bid in, does that impact your ability to bid in to these?

Again, I don't think the timing is pretty clear right now. I think that's something that Now Core will update when they are ready to do that and so obviously we look forward to that update. But as it relates to those projects and the opportunities to supply energy, we have always looked at that at this stage as being surplus energy that exists in the market. Surplus is that exists from projects as they come on and also clean energy, light and wind. And so those are the projects that will be important to that and so that project we have proposed which is the Atlantic Link gives us the ability to collect energy from Northern Maine from New Brunswick and also from Labrador and Newfoundland and so the flexibility that the project has to gather energy from all those locations we believe allows it to be probably the most flexible project the region will see. And so with that flexibility it does allow us to incorporate timings and new resources as they become available.

Got you. Thanks, Chris.

Okay. Thank you.

Your next question comes from the line of Robert Kwan of 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 am wondering does the 1.3% increase per year for the fuel side of things, is that expected to fully dispose of the and fully recover the Maritime Link load costs as it relates, not obviously fully recover the whole project but just the cost in those specific years?

Yes, Robert Scott speaking, so that's exactly right. That's 1.3% expected to cover the expected fuel costs through that three year period which includes the Maritime Link.

Okay. And how does the rate freeze on the non-fuel square up with any unforeseen cost or capital investment in the rate base?

Well within that estimate, we have factored in within that three years our view to cost profile through that period. Obviously we have got a long operating history and so we understand the variability some of the costs input within that and we fully factored into that rate freeze through to 2019.

Is there wiggle room then in terms of contingency or are there going to be explicit defer mechanisms or ability to have rate rider unforeseen costs?

Well, if it's completely unforeseen and unpredictable there is a mechanism within the structure that allows us to deal with that but with all of the majority issues we forecast where we will be and we are comfortable the business can manage through that period and do that on behalf of us.

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

So your second question Robert, we didn't release any of the reserves back into the quarterly results and the majority of the $3.4 million if tax affected would have gone to the bottom line. There was some loss of industrial load that was not weather related but it would be probably, maybe 40% of that Robert would have been lost to industrial load in the weather.

Okay. That's great thank you very much.

Thanks Robert.

And there are no further questions in the queue at this time. We turn the call back to the presenter.

Okay. Thank you very much for your participation on the call today and for your interest in Emera and speaking of that interest we are holding our AGM at the Design Exchange in Toronto next week, 2 PM on Tuesday, May 17 so we look forward to seeing you there. Thank you all very much and have a good day.

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