Emera Incorporated (EMA) Q1 2015 Earnings Report, Transcript and Summary

Good afternoon. My name is Tiffany and I will be your conference operator today. At this time, I would like to welcome everyone to the Emera First Quarter 2015 Results Conference Call. [Operator Instructions]. I would now like to turn the call over to Scott LaFleur, Manager of Investor Relations. 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; Scott Balfour, Executive Vice President and 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 then Scott will review the financial results in detail. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts. Please note that all amounts are in Canadian dollars with the exception of Emera Maine and Emera Caribbean, where segment results are reported in U.S. dollars. I'll take a moment to remind you that this conference call may contain forward-looking information which involves certain assumptions and known and unknown risk and uncertainties that may cause actual results to materially differ from those that are expressed or implied by the comments. Those risks include but are not limited to weather, commodity prices, interest rates, foreign exchange, regulatory requirements and general economic conditions. In addition, please note that this conference is being widely disseminated via live webcast. And now, I'll turn things over to Chris.

Thank you, Scott and good morning, everyone. Adjusted net income for Q1 of 2015 was CAD171.6 million or CAD1.18 per share, compared to CAD146.6 million or CAD1.03 per share for Q1 of 2014. This represents 15% growth in adjusted earnings per share quarter over quarter. Our strategy helped all of our businesses achieve growth this quarter, led by growth in earnings at our New England gas plants. Scott Balfour will take you through the details of the quarter later in his remarks, but first I'd like to touch on some of the key strategic and operational milestones Emera reached this quarter. Emera Energy had a very strong start to the year. Non-regulated electric margin reached CAD88.9 million, more than double the margin achieved in the first quarter of last year. This primarily reflects an increase in realized spark spreads for the New England facilities which averaged CAD39 per megawatt hour compared to $16 per megawatt hour in Q1 of 2014. Market spark spreads were consistent quarter over quarter at about $4 per megawatt hour. This performance reflects Emera Energy's hedging activities which saw almost 50% of the New England portfolio hedged at an average spark spread of $51 per megawatt hour. That was for the first three months of 2015. Needless to say, we're pleased with how our New England generation investment is performing. We're taking advantage of the spring shoulder season to complete a major maintenance upgrade project on the second gas turbine at Bridgeport which will add an additional 20 megawatts of capacity to that facility, on top of the 20 megawatts we added in the fall of last year. By the end of this month, Bridgeport will effectively be completely renewed, with a 2% to 3% improvement in heat rate and ready to perform. Trading and marketing also had an outstanding quarter by most measures except by comparison to last year. As expected, margin was lower, at CAD38.8 million in Q1 of 2015, reflecting a return to more normal levels following the unprecedented market conditions of Q1 of 2014. That said, these results represent the second strongest year in the business's history and compare favorably to CAD20 million in margin generated in Q1 of 2013 and CAD5.3 million earned in Q1 of 2012. We also believe it demonstrates a natural hedge between the marketing businesses and the natural gas generation business, as it relates to volatility. [Technical Difficulty]. We finalized our last remaining major contract for transmission line construction, meaning that all three major contracts have now been awarded. And with over 90% of project costs contracted and understood, we have a high degree of confidence that the cost to complete the project [Technical Difficulty]. Construction and manufacturing is moving ahead, with civil construction now preparing the sites for the converter stations in Newfoundland and Nova Scotia. Transmission line construction is also underway, with steel for transmission towers to be delivered in mid-year. And manufacturing of the sub-sea cable has begun. In April, we signed a socioeconomic agreement with the Nova Scotia Mi'kmaq. This is an addition to a similar agreement Emera signed in Newfoundland and Labrador late last year with the Qalipu Mi'kmaq. We continue to advance the project from an environmental and community perspective. For Nova Scotia Power, the focus remains on managing costs to ensure stable, affordable and predictable rates for our customers. We continue to work positively and productively with our regulator, stakeholders and the government of Nova Scotia. Nova Scotia Power and New Brunswick Power recently announced a pilot project to implement a cooperative dispatch of our power plants to improve efficiency and reduce cost for customers, while also ensuring both provinces continue to meet their renewable energy and emissions standards. The project is about using the existing interconnection between the provinces and optimizing the generation and transmission assets. The pilot program is planned for 12 months and is forecast to provide cost savings of up to CAD20 million annually. This project builds on our long-standing strong relationship with the New Brunswick Power and continues our focus on regional cooperation in the energy sector. This past winter, New England had colder temperatures than last year; however, prices were not as volatile, primarily because more LNG was available to serve the market. That said, prices for customers were higher due to gas price volatility from the previous winter. High prices have sustained interest by the state governments in finding solutions to price volatility, as well as legislative renewable standards and greenhouse gas reduction. In February, the states of Massachusetts and Connecticut, as well as Rhode Island, issued a draft RFP for clean energy and transmission. This Tri-State RFP is seeking at least 2.5 terawatt hours of wind and/or hydro energy and the transmission to deliver it to market. There was a public comment period regarding the draft RFP and we expect it to be formally issued this summer. We believe that AC transmission upgrades to enable renewable generation would be among the most cost-effective options for electricity customers and are actively working towards responding to this RFP. Emera continues its partnership with Central Maine Power to propose upgrades in the AC transmission system that would allow more energy to flow from northern Maine and Canada. Emera is well-positioned to be responsive to the region's needs and we're focused on delivering the right solution to this market. Moving to the Caribbean, Emera has initiated discussions with stakeholders in Barbados regarding a strategic vision to achieve 100% renewable energy for the island by 2045, utilizing smart grid technologies. This would involve small- and large-scale renewable energy projects, the integration of electric vehicles and smart grid infrastructure. Energy policies and frameworks would also need to be put in place enabling this goal. We believe this vision will make Barbados a showcase to the world for the integration of renewable energy technologies. Our utility scale solar plant in Barbados would be part of this plan and is progressing well. We're clearing land and obtaining land-use approval with our next step being the installation of equipment. An advanced metering infrastructure pilot project is also underway in Barbados. These projects are the initial steps towards a strategic vision for the region and implementation of an advanced smart grid for this island. Emera is executing on its strategy. It wasn't very long ago that earning CAD1.18 took an entire year. The growth this quarter and the improved visibility of our earnings from the Maritime Link provide continued confidence in achieving our growth targets beyond 2015. With that, I'll turn things over to Scott, who will give you a more detailed update on our financial results for this quarter. Scott?

Thank you, Chris and good morning, everyone. Our first quarter results were released earlier today and are now on the Emera website. Emera's consolidated net income for the first quarter of 2015 was CAD160.1 million or CAD1.10 per share compared to CAD202.8 million or CAD1.43 per share in the first quarter last year. Our first quarter results are normalized for mark-to-market losses. Adjusted net income was CAD171.6 million or CAD1.18 per share, compared to CAD146.6 million or CAD1.03 per share last year. The CAD25 million increase in adjusted net income is primary due to the positive impact of a strong U.S. dollar and increase contributions from Emera Energy's New England gas plants which offset the expected reduction in trading and marketing margin due to very strong market conditions in the first quarter last year. Also of note, adjusted net income in the first quarter this year included an CAD11.5 million after-tax gain or CAD0.08 per common share regarding the sale of Emera's 49% interest in the Northeast Wind Partnership. There were no similar gains recognized in the first quarter last year. Operating revenues decreased 14% to CAD900.3 million in the first quarter this year. The decrease was primarily due to mark-to-market impacts and reduced trading and marketing margin, partially offset by increased revenues at Nova Scotia Power, as a result of recovery of prior years' fuel costs and load growth. Turning now to our segmented results, Nova Scotia Power contributed CAD68 million to consolidated net income in the first quarter of 2015, compared to CAD66.8 million in the first quarter last year. The increase was primarily due to the timing of regulatory deferrals and increased electricity sales, partly due to weather. This was partially offset by increased tax expense related to lower pension contributions and increased income before provision for income taxes. Emera Maine contributed CAD11.5 million to consolidated net income in the first quarter of 2015, an increase of CAD1.1 million compared to the first quarter last year. The higher net income was primarily from the impact of stronger U.S. dollar. Emera Caribbean contributed CAD8.8 million to consolidated net income for the first quarter of 2015 compared to CAD6.6 million for the first quarter last year. The increase in net income is primarily due to decreased OM&G expense and the positive impact of the stronger U.S. dollar. The Pipeline segment contributed CAD9.9 million to consolidated net income in the first quarter of 2015, compared to CAD7.2 million in the same quarter last year. The increase of CAD2.7 million is primarily due to higher equity earnings from Maritimes and Northeast pipeline, due to increased interruptible transmission revenue, increased tolls and foreign exchange gains due to the stronger U.S. dollar. As Chris mentioned earlier, Emera Energy delivered another strong first quarter. Adjusted net income was CAD76.4 million in the first quarter this year, an increase of CAD15.4 million compared to the same period in 2014. The higher adjusted net income was primarily due to increased contributions from the New England gas generating facilities and the gain on the sale of our Northeast Wind investment, partially offset by the expected lower trading and marketing contributions. Our Corporate and other segment posted a CAD3 million loss in the first quarter of 2015, compared to a loss of CAD5.4 million in the same period a year ago. The improved results are primarily due to increase equity earnings from our investment in Algonquin Power and NSPML, partially offset by increased preferred share dividend as a result of a share issuance in the second quarter of 2014. That's all for my financial overview and now we'd be happy to take your questions.

[Operator Instructions]. Your first question comes from the line of Paul Lechem with CIBC. Your line is open.

Just wanted to understand a little bit more about the dynamics of what's going on in New England. Wondering if the conditions that contributed to Q1 have persisted, if any of the hedges remain in place for Q2 and also your view as to, could these conditions reappear next Q1? Has anything changed in the fundamentals that could alter the dynamics for next Q1?

Paul, it is Judy Steele. Our, I'll call it, our $51 hedges rolled off at the end of March of this year and it's fair to say that our ability to put such a favorable hedge on was partially a hangover from the winter of 2014. But that said, when I look forward to the end of this year and the beginning of next winter, we do have about 30% of our available capacity hedged at $36, so not as attractive but clearly very, very favorable to other - things we're seeing in the general day-to-day markets and where we're able - what we've been able to achieve earlier in our ownership. So very, very nice $51, but $36 is not too shabby either.

Okay. Is that the spot spread that you've locked in?

Yes, margin. Yes.

And do you see anything different, I'm just trying to think about the fundamentals and trying to get more gas into the region. I'm assuming that none of the pipelines that could alleviate the situation will be ready by winter 2015/2016 that would actually change the fundamentals to any degree?

That's right. There won't be.

When you actually see the dynamics - the fundamentals in the market easing up so that those upside opportunities will no longer exist?

Toward the end of 2016, we may see some shift, but again, there's not a significant amount of [indiscernible] capacity at that point, so we'll see what kind of impact it has.

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

Just following up on the New England performance. We've clearly got some hedges that are going to be rolling off and one just rolled off, but do you see some offset from the hedges rolling off with just the increasing capacity payments out into the future? Not so much into 2015/2016, but when you look really beyond that time frame?

Definitely. Yes, starting with the results of FCA9 which is 2018/2019, there is over CAD100 million of capacity revenue over that two-year period, so for sure that capacity revenue is going to make an increasingly important contribution to the value of the facilities.

So as a follow-up to that, when you look at the end of the decade, how do you think about just the proportionality of capacity payments versus just straight-up energy for your existing facilities in New England?

That's a challenging question, Andrew, because it's hard to predict the energy market that far out. I think though it will kind of get closer to 40%, 50% capacity, where we have to get the results of the next capacity auction, of course, to see where we really think the long-term trend is going to be on capacity. We're only getting these one year at a time, but certainly it would be an increase probably 40% to 50% capacity.

Andrew, it's Chris. That whole market is in substantive transition and as we said earlier in my remarks, we actually are seeing other sources of new energy come into the market, as well and we're focused on building some transmission, et cetera. So when we think about that market, we think about it as a portfolio. Our trading and marketing business obviously helps us substantially when it comes to managing those plants and ensuring we maximize value there. But at the same time, some of our other activities, like the transmission work and the work we're doing on the renewals front, will also contribute. So we just see that market as becoming a bigger and bigger opportunity for us over time and we want to make sure that we have a portfolio of assets and therefore are able to participate in the ups and downs as it occurs across that whole market.

And then if I may just ask a question on the financing. This is to Scott, just how you're seeing the pref market at this point in time and maybe comparing the pref market to the debt market, so what you think is the most attractive in the capital mix for the financing plan out to 2017?

I would say, our overall view and strategy wouldn't have changed from the kind of mix of financings structure that we had last talked about and within the investor materials. Clearly, the pref market has tapered back in the last couple of months and we continue to keep a watchful eye, not just on what kind of coupon we could look at for pref, but also the reset rates. No surprise that our most recent financing activity, of course, was a long-term debt financing for Nova Scotia Power. There's no great urgency as we sit today, as it relates to our financing needs and so we're able to take advantage of market opportunities as they arise. But fundamentally, we wouldn't see much of a shift of our current thinking at the Emera level between our pref and debt strategy. It is just a matter of picking the right spots.

Your next question comes from the line of Matthew Akman with Scotiabank. Your line is open.

I had a question on the earnings and then one on strategy. Regarding the earnings, I don't know if this is a question for Scott or Judy, but is it fair to say that the spark spread hedges came mostly in the form of below-market gas as opposed to above-market power sales? The reason I ask that is because it looks like the unregulated fuel for power generation was down quite substantially year-over-year?

I'd say it is a combination, Matthew. I can't give you the exact percentage, but it was favorable in both directions.

And Matthew, just another thing to remember is that our Bridgeport facility which is our largest facility, has access to generally lower cost gas than most of the rest of New England, because it's sitting on the air cross system. In fact, as the Constellation Pipeline comes into that system, we expect to have much more direct access to Marcellus gas. So we will probably continue to have, generally speaking, lower cost gas than the general market in New England and therefore be able to make slightly higher spreads on that particular facility.

Just a follow-up and maybe this is a question for Scott, but if you have below-market gas, you can sell it in the market for a higher price and book marketing profit or burn it and book generation profit. How do you decide whether that goes into marketing or generation? It feels like this quarter most of it got put into the generation bucket and last year it was the marketing bucket?

First, Matthew, it's not below-market gas sitting in a fungible hub, it's below market gas in a facility that can turn it into electricity that's can get to the hub. So it does, more or less, require us to actually make electricity.

Two things. First of all, we have capacity payments in the plants, so we're actually obliged to offer the plans in the day-ahead market, so we don't really get to optimize the gas to the extent unless we're not picked up. But secondly, I just want to remind you, Matthew, that they are selling into the New England market where the electricity price is set by the AGT gas price. We're buying at Iroquois, so it's more about the transmission of the electrons into the richer market than it is about the gas being - it being advantageous to sell the gas in its own pocket.

The thing I would add to that, Matthew, those are the technically correct answers to the question, but the other important piece is that from a strategic perspective, it does highlight the value that we saw from the beginning of having a knowledgeable base within this market, having a marketing and trading debt that's already established in this market and the complementary nature that, that brings to owning competitive generation in that market.

Just on a strategy side, I noticed Central Maine Power is supporting Access Northeast pipeline, the Spectra project. I don't know if I have lost track, but I'm just wondering where you guys sit in terms of your utilities in New England, in terms of supporting the pipeline capacity?

Gerry is on the line. He may want to speak to that from a Maine perspective.

Yes, that was a recent announcement by Central Maine Power and in early discussions on the same subject, we've been supportive of that, as well. Maine statutes allows for $75 million a year to electric rates for Maine customers to access or take out reservations in order to get some gas transmission capacity built.

Okay. Any indications of which project or projects you guys might support?

No. Not at this point.

Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open.

Just on New England and - you had it, as you mentioned, one-half hedged at $51 on the spark spread. Is that just a flat physical number. I am just was wondering because we saw a lot of spiking mid- to late February and into early March and I'm sure your desk is trying to optimize the plants. Was there anything shaped differently than what you'd expect just on a straight physical run?

No. It was actually - we had it hedged, that was around-the-clock, $51, Robert.

So it is going to be good clean comp, Judy, just again - $36 you gave us, as we look forward here?

Yes.

Okay, perfect. As you just look at New England, how do you like you capacity position right now? Would you like to get bigger given you've divested the renewables with Northeast Wind?

From a portfolio perspective, absolutely. We want to have more exposure to this market. But at the end of the day, it is all about value and we need to continue to see value in order to make further investments. So what we're mostly focused on right at this moment is replying to that RFP that is in the market for 2.5 terawatt hours. We see the opportunity to potentially get some surplus energy out of Newfoundland. We also see the opportunity to get some wind potentially into that RFP and also, clearly, we're focused on making sure the transmission is there to deliver the energy. Those are the things that were really mostly focused on right now, but we're always looking and we certainly would never rule out another investment if in fact we saw a value.

And Chris, you bring up a good point, obviously value matters. Can just comment as to what you're seeing on value, both on gas versus renewables and specifically what it might take to help, as you alluded to the transmission investment trying to back the line?

For us, the challenge right now is we actually are seeing substantial congestion in that market. One of the challenges that the First Wind assets were facing was substantive congestion in northern Maine. So that's really a part of - there's not that much sense building more in that market until we can actually get our way through and ensure that energy gets delivered. So that's a big part of what we're focused on, looking at how we can utilize some of our existing assets, like the interconnections we have between New Brunswick and Maine right now and looking at how some of the new energy from Muskrat Falls and that kind of investment can enter this market. So those are the things that we believe are going to be important as that RFP actually gets formalized.

Okay. Just actually, you mentioned, Chris, congestion which is a good segue into my last question. Any update on any projects in terms of your partnership with Central Maine?

I would say no additional update right now. We announced the Bridal Path activity with EDP and we continue to work towards being able to submit into this RFP. Our objective would be to make sure that these AC upgrades are important to a number of different bidders in that market. I'd also just ask Gerry if he had anything he wants to add.

No. That's right on, Chris. We expect a formal RFP to come out probably towards the end of this summer and our current efforts would be in responding to that with a portfolio of transmission upgrades and potential partners in the context of the RFP to support that 2.5 terawatt hours.

Your next question comes from the line of Ben Pham with BMO Capital Markets. Your line is open.

Just going back to Emera Energy and the hedging. I wanted to check, have you got a formal hedging policy in place, as you head into the New Year? Initially, when you acquired the assets, you were fine-tuning that hedging policy?

So then we would characterize it now as saying that we're comfortable hedging up to 50% of our total capacity, assuming that we have market conditions that we think are favorable. We basically, by the end of the month, will have completely revitalized the Bridgeport facility which goes a long way to making us comfortable with taking out term hedge positions. So that's our current thinking. 50% generally winds up being the target.

Okay. And just on hedging, I'm not sure if I missed this, the hedges is it - are you engaging and is it a heat rate hedge that you have in place? Is there a risk that gas and power hedges could be uncorrelated, that it can go--?

No. We're fixing the price of the gas and the price of the electricity.

Okay.

Financially.

Okay. It's locked in.

The challenge continues to be to make sure the plants can operate, so that's a primary focus for us, but that's part of why we've made the investments we've made in the plants. And we've continued to refine our operating approach to these facilities and we're seeing some very, very good reliability these days.

[Operator Instructions]. There are no further questions in the queue at this time. I turn the conference back over to our presenters.

Okay. Thank you very much. We really appreciate people taking the time today for your participation in the call and your interest in Emera and hope everyone has a great rest of the day. Thanks a lot.

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