Emera Incorporated (EMA) Q3 2021 Earnings Report, Transcript and Summary

Good day and thank you for standing by. Welcome to the Emera Quarter 3 2021 Analyst Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, David Bezanson. Please go ahead.

Thank you, Elisha, and thank you all for joining us this morning. Emera's third quarter 2021 conference call and live webcast. Emera's third quarter earnings release was distributed this morning via newswire and the financial statements, management’s discussion and analysis and the presentation being referenced on this call are available at our website at emera.com. Joining me this morning’s call are Scott Balfour, Emera's President and Chief Executive Officer; Greg Blunden, Emera's Chief Financial Officer; and other members of Emera’s management team. Before we begin, I will take a moment to advise you that this morning's discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide. Today's discussion and presentation will also include references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. And now I will turn things over to Scott.

Thank you Dave. And good morning everyone. This morning we released our third quarter results and I’m pleased to say we continue to deliver steady, predictable growth. Our third quarter adjusted earnings per share was $0.68 compared to $0.67 in Q3 of 2020. When you adjust for the timing of preferred share dividends to make it an apples-to-apples comparison, our adjusted earnings increased by 10% compared to the same quarter last year. And for the year-to-date, we’ve delivered 12% adjusted earnings per share growth from $1.93 per share for the first nine months of 2020 to $2.17 per share for the same period in 2021, even in a strengthening Canadian dollar environment. This growth reflects the overall strength of our business, underpinned by our regulated utilities. Contributions from our regulated businesses have been increasing as we continue to advance our strategy by making rate base investments to reduce carbon emissions and improve reliability, while never losing sight of affordability for customers. As you know, the rate based investments we're making on behalf of our customers in execution of our strategy to safely deliver cleaner; reliable and affordable energy also drives our earnings and cash flow growth. This year, the foundation of our capital program has been our major project investments at Tampa Electric, including the Big Bend modernization project and the second phase of our solar program. We've also continued to make investments across the portfolio to decarbonize, to increase infrastructure resiliency, and to provide our customers with more choice and control, including the deployment of smart meter technology. With 70% of our expected 2021 spend completed at the end of the third quarter, we remain on track to make over $2 billion of rate based investments in 2021, all while keeping our team safe and our capital projects on time and on budget. Decarbonization has been central to Emera’s strategy for over 15 years. And now as policymakers, stakeholders and customers continue to increase their focus on reducing carbon emissions; Emera is as well positioned as ever to deliver growth and value for our customers, communities and shareholders. Our decarbonisation journey began here in Nova Scotia. Over the last decade, Nova Scotia Power has tripled the amount of renewable energy it delivers to customers, and reduced its CO2 emissions by more than 30%. Nova Scotia Power is on track to deliver nearly 60% of its energy from renewable sources in 2022. And in August, we reached another important milestone in our decarbonization journey when hydro energy for Muskrat Falls began flowing to Nova Scotia through the Maritime Link. Having access to this source of clean energy will allow us to continue reducing the carbon intensity of our generation fleet and keeps us on track to meet the Province of Nova Scotia renewable energy targets. Last month, the Nova Scotia provincial government introduced Climate Commitment legislation that included the retirement of coal generation assets and supply of 80% renewable energy by 2030. Meeting these targets will require incremental investment in cleaner energy solutions, storage and transmission, as well as alignment between regional utilities and provincial and federal policymakers. The team continues to advance discussions with stakeholders on next steps to achieving our shared goal of transitioning to cleaner energy in Nova Scotia by 2030. The Eastern Clean Energy Initiative, the new transmission component of which is referred to as the Atlantic Loop represents a significant opportunity to work collaboratively with our neighboring utilities in Eastern Canada, and various levels of government to facilitate the transition off coal at an accelerated pace without undue rate impacts for our customers. In addition to new transmission capacity, this initiative includes investment in renewable sources, particularly wind as well as transmission infrastructure upgrades, and investments in battery storage, all to replace the energy and critical capacity that Nova Scotia powers coal plants provide today. We continue to be encouraged by our on-going discussions and hope to be in a position to provide a more clear sense of this significant project in early 2022. Earlier this week, Tampa Electric announced their vision for its cleaner energy future, aligning with Emera’s Climate Commitment announced earlier this year. Since the year 2010, Tampa Electric has reduced coal usage by more than 90% and cut CO2 emissions in half, even while demand for power has increased 25%. In addition to a net zero vision by 2050, Tampa Electric announced a series of interim goals that it will target on the journey to cleaner energy including a 60% CO2 emissions reduction by 2025 and an 80% reduction by 2040 relative to their year 2000 levels. It's been a busy year for us on the regulatory front. Most recently, the Nova Scotia Power Maritime Link team filed the final project capital cost application with the UARB in Nova Scotia. And in the Caribbean, both Barbados Light & Power and Grand Bahama Power recently filed rate cases. We expect to have final decisions on all these matters in early 2022 or before. Achieving successful and balanced regulatory outcomes is critical to our success. We've consistently demonstrated our ability to secure fair and reasonable decisions across the business, with rate case settlements over the last year at New Mexico Gas, Peoples Gas, and most recently at Tampa Electric. Last month, Tampa Electric's uncontested settlement agreement was unanimously approved by the Florida Public Service Commission. This settlement represents a balanced agreement that supports our strategy to provide Tampa Electric’s customers with affordable, cleaner and more reliable energy. Even with these new rates coming into effect on January 1 of 2022, Tampa Electric’s rates are expected to continue to be among the lowest in Florida and about 15% below the current national average. These new rates not only support investments already made to decarbonize the generation mix, but provide full support for the completion of the Big Bend modernization and the second wave of new solar generation, while also providing a mechanism to recover the cost associated with the accelerated retirement of coal generation. Before I pass the call to Greg, I want to take the opportunity to update you on some upcoming leadership changes at Peoples Gas. T.J. Szelistowski is retiring this December after 42 years with the company, 42 years. I know that sounds hard to believe, but he joined the company as a Co-op student back in 1978. And as President of Peoples Gas since the acquisition of TECO, since our acquisition of TECO, T.J. has been instrumental in driving the utilities growth, its strong safety performance, and its outstanding customer service. Helen Wesley will be appointed as the next President of Peoples Gas on December 1 when T.J. retires. Helen joined our team last year as the Chief Operating Officer at Peoples Gas. She's a dynamic leader, who were built on the growth and momentum of Peoples Gas as the team continues to deliver for customers in Florida. Thank you, T.J. and congratulations, Helen. And with that, I'll pass it over to Greg.

Thank you, Scott. And thank you all for joining us today. This morning, we reported third quarter adjusted earnings of $175 million and adjusted earnings per share of $0.68 compared to $166 million and $0.67 in Q3 of 2020. For the nine months, year-to-date adjusted earnings were $555 million and adjusted earnings per share was $2.17 compared to $477 million, and $1.93 for year-to-date 2020. Emera’s adjusted earnings per share increased for the quarter and year-to-date despite the foreign exchange headwinds of $0.03 and $0.11 respectively. Our adjusted earnings exclude mark-to-market adjustments. Emera Energy’s Q3 mark-to-market loss had a very material impact on reported earnings. I gave you a refresher on that situation in Q2, and I'll deliver a condensed version now as a reminder. Emera Energy has deals with utilities and producers to buy or sell gas for a term that comes with a release of the customers transport. Mark-to-market arises on the price difference between where the gas to source and where it is sold, which is fully offset by the value of the corresponding gas transportation asset. But because the gas is mark-to-market and the transportation asset is not that results in some net mark-to-market gains or losses recorded in income. In Q3, the magnitude of the mark-to-market loss is particularly high because prices have surged in the Emera Energy's primary sales market New England. LNG is the marginal fuel there in winter and global LNG prices are high. As always, it is important to emphasize that these situations have no actual economic market exposure because regardless of the difference in the value of the gas between the receipt and delivery point, Emera Energy has a transportation capacity that enables it to move the gas to the point at which it is priced. As we'll take you through now, growth in adjusted earnings per share was primarily driven by steady growth in our core regulated utilities, lower corporate costs and improved earnings in our market and trading business partially offset by foreign exchange in a higher share count. Although third quarter results are flat relative to 2020, when you adjust Q3 2020 for the preferred share dividend that would have normally occurred in that quarter, earnings per share increased by $0.05 over Q3 2020. This increase is a result of our portfolio of businesses that performed well in the quarter. Our gas utilities led by Peoples Gas continued to benefit from new rates and continued growth in its customer base. Excluding the impact of a stronger Canadian dollar, Peoples Gas delivered C$10 million of increased earnings compared to Q3 2020. Emera Energy's marketing and trading net earnings increased $7 million through the strength of market pricing and higher volatility. Our Canadian utilities contributed modestly to growth in third quarter with a higher contribution from Nova Scotia Power due primarily to lower income tax expense. And excluding the impact of foreign exchange, higher APTC earnings increased the contribution from Tampa Electric as we continue to invest in our Big Bend modernization and solar projects. This was partially offset by higher depreciation and amortization expense, reflecting increased capital investment and the effect of the 2020 amortization settlement in Q3 of last year. Growth from these businesses was partially offset by the timing of the preferred share dividend in 2020, a stronger Canadian dollar and a higher share count. We continue to proactively manage our exposure to the strengthening Canadian dollars to economic foreign exchange hedges. In Q3, we recognized $4 million in realized gains on these hedges and entered into additional FX forwards. For the remainder of 2021, we have $56 million in hedges at an average rate of approximately $1.35. Similar to the quarter, the year-to-date increase in adjusted earnings per share of $0.24 was driven largely by higher earnings at Emera Energy due to favorable market conditions as well as strong results from our gas utilities due to new rates and continued customer growth. Our corporate segment benefited from $29 million of lower interest expense, primarily due to the retirement of corporate debt, lower interest rates and the strengthening Canadian dollar. In realized gains and foreign exchange had just contributed $17 million to the increase over prior muting the impact of foreign exchange headwinds from our U.S. operations. And increases in our Canadian and Florida Electric segments were consistent with the factors that impacted the quarter as discussed a moment ago. Foreign exchange impacts, share dilution and the sale of Emera remain partially offset the growth from our core operations. Operating cash flow year-to-date is down $66 million or 6% compared to 2020, primarily as a result of incremental fuel costs associated with winter storm Yuri at New Mexico gas. And cash flow at our regular utilities has been negatively impacted by the increasing commodity prices we are seeing around the world in particular natural gas prices, which have increased two fold since January 1. Although our cash flow results currently reflect the impact of the higher fuel costs incurred across the business, there are regulatory mechanisms in place to recover these prudently incurred costs and customers. And while there is no impact on our earnings, it's important that the timing of cash flow recovery is actively managed by working with our regulators to balance affordability for our customers. The most recent evidence of this was a regulatory approval in New Mexico to defer the cost of winter storm Yuri and collected over a 30-month period beginning on July 1 of this year. This ensured customers were not overly burdened, and shareholder interests were protected. Now before I turn the presentation back over a Dave, I would like to mention that at our upcoming investor Day on December 1, we look forward to walking you through our new three year capital forecasts, updating you on our key strategic initiatives and introducing you to some of our leadership team. Although we wish we could connect in person, we have decided in the interest of safety to move forward with a virtual event for 2021. And with that, I'll turn it back over to Dave.

Thank you, Greg. This concludes the presentation. We would now like to open the call for questions from analysts.

[Operator Instructions] Your first question from the line of Maurice Choy, RBC Capital Markets.

Thank you and good morning. First question relates to a topic you mentioned Scott. You mentioned that with regards to the move to decarbonize Nova Scotia, you are encouraged by the on-going discussions with the potential update in early 2022. Given that we've got, the federal and provincial government support, especially given recent elections on both sides, can you provide some color on where if any pushback currently is that and if you see elements of the Atlantic Loop, and the 2030 off coal and Nova Scotia, will you see elements of that part of your plan next month?

Yes, Maurice, thanks for the question. And Peter Gregg's here with me and he can contribute to this too. But broadly Maurice, I don't think we're really seeing any resistance to this really, the idea of this project around looking to optimize the energy resources that exist in our neighboring provinces to help Nova Scotia and New Brunswick, frankly, both to decarbonize. A lot of this is around the effort to do it on a basis that doesn't sacrifice affordability for customers. And so with that, it's about aligning all the parties involved in this, a number of provincial governments, a number of provincial utilities, and of course the federal government in way that has the you know sort of benefits to all those parties. And so part of this really is, is looking for support from the federal government in order to assist in this in a fair way for Nova Scotians, where today, the cost to retire the remaining coal plants in Canada, 55% of that’s in Nova Scotia where we only have 3% of the population. And so looking for federal government to help with this to insurance affordable, and frankly, I don't think it's anything above resistance at this point. It's just really complicated and takes time to work through. In the meantime, Nova Scotia Power is working its own plan in terms of things that needs to be done within its own system. Here with investments, as I mentioned, and in new, new renewable resources, and wind and in storage, and transmission upgrades, will all be part of that, as well and will form part of Nova Scotia powers capital plan over the over the years to come. Peter, anything you'd like to add to that?

Scott, I think you said that well. I think you just maybe re-emphasize that. I think since we've had the provincial election and federal election, I think I agree with Scott, there is alignment, Swizzle [ph] alignment on 2030 goals for decarbonisation. And I think, good support for our plan that we put forward, particularly with the provincial government. So I think there is alignment amongst many parties. But as Scott said, with many parties involved, it adds a level of complexity. And so but continued positive momentum on that goal.

Great. And maybe my second question I just wanted to pick up on your decision to extend your dividend growth rate to two years to 2024. At the same time, in the MD&A, you mentioned that you continue to see the payout ratio to be above the target rate, target range of 77 5%. Given it now you have the Tampa Electric rate case approved, how has that approval improved your ability to or maybe visibility and getting back to the target payout ratio?

Yes, Maurice this is Greg. I'd say it was pretty -- the settlement was pretty much in line with what our expectation would have been. And so we'll see, we believe a meaningful improvement in our payout ratio over the next couple of years. But we still would expect that we'll likely not get into the sweet spot of the 70 to 75 until sometime after 23 or 24. Assuming the Canadian dollar stays at these levels and we don't see a material weakness in the Canadian dollar over that period.

Great, thank you.

You're welcome.

Your next question comes from the line of Ben Pham, BMO.

Hi, thanks. Good morning. Going back to [Indiscernible] are you able to notice there's still probably a lot of items you need to need to pin down for -- but the frame it major from the perspective of Maritime Link, size and timing and, and there's just able to make payment for us to tie gauge cash backs and the timing and whatnot?

Yes, Ben, I understand the question and obviously would love to be able to, to do that. The challenge right now, of course, is until there's more clarity as to the role that all those parties are going to play we've just been hesitant to, to lock in and set expectations around what it means from a from a capital cost perspective that's relevant for Nova Scotia Power and Emera. I do know there's a number out in the media of roughly a $5 billion project and order of magnitude that's, that's obviously about right. But looking as to you know, what the component part of that is for Nova Scotia Power and therefore, the CapEx and investment profile for Nova Scotia Power and Emera, it's just, it's still too soon to, to look at those numbers. And that's why I say we're hoping that in early 2022, once we've got more clarity on all of this as to where all the parties are, that we'll be in a position to provide more clarity then.

Okay. And then on the bouncy, you've mentioned maybe your sweet spot in the payout ratio and you've also mentioned hitting the credit metrics next year. When you do reach there 2022, do you have a preference for staying in that that range as you add cash backs are you considering I think about maybe adding a bit of buffer to those credit metrics over time?

Yes, Ben good morning. It's Greg. I mean first and foremost what we've been focused on is getting our balance sheet to our targeted capital structure, and getting our credit metrics to the 12% FFO and CFO to debt and how the middle level that's sustainable over the long term, that doesn't mean that we're going to stop there. But we, as we see the growth in the business beyond 2022, we think there will be inevitably a buffer built into it. But most importantly for us is to get to those threshold levels, and how the mid-point where they're sustainable over the longer term.

Okay, that's great. Thank you very much.

[Operator Instructions] Your next question comes from the line of Rob Hope, Scotiabank.

Morning, everyone. Another question on the Atlantic Loop projects seems like a nice solution to phase out coal, but long duration or long distance transmission systems are very difficult to permit as we learned in Maine. What would plan B be for Nova Scotia Power? And like, do you think there is sufficient wind resources and firming resources even possible in the province to help you meet that 2030 goal, and really have a dual track process of kind of Option A and Option B and, and when you have to start engaging the regulator on that?

Rob, it's, Scott. And so, look, I mean, we're utility, which means we contingency plan everything. So yes, we do have, plan B, C, and D and so on. But we believe this is the right and best plan for Nova Scotia, frankly, for the region as a whole. And look, one of the, one of those contingency plans could be, we build more gas generation capacity in the province to backstop more wind, but we prefer not to do that. Both because that has its own carbon emitting profile, of course, but also we know that the access to natural gas, Atlantic Canada's is constrained. And so that's, that's one option. There are others, ideally creating more transmission capacity in order to provide, in particular the incremental capacity that's required to backstop more intermittent renewables. The Maritime Link is, is a critical assets in in achieving that future. But, but frankly one more, one more big extension cord, as I've been describing to some investors, is something that really makes the most sense to achieve the off coal and 80%, renewable objective for Nova Scotia Power. And that continues to be the focus for Peter and the team. And, as I say, we're encouraged, we're optimistic, but still some lots of work to do before in a position to talk about it with any certainty.

I appreciate the color on my four part question.

So, yes, Peter. Rob, I think Scott said it. Well, I think our preferred plan, which includes the Atlantic Loop, really is the preferred option from a customer affordability perspective, from an achievability perspective, and from a reliability perspective, Scott's right, we do contingency planning, and point you to our integrated resource plan that we published last year as part of our regulatory requirements. And so it would give you a sense of the kinds of considerations we make as we do that long range planning. And that's really all about that.

Thank you. And then just the second question, this one's for Greg. The commentary on higher fuel costs weighing on cash flow, in 2021. Just want to confirm that dominantly at New Mexico as you did have that course correction, adjustment at Chico [ph]. And an SPI the fan should be covering off most that just want to get a sense of, whether or not you're seeing the other kind of inflationary pressures on fuel impacting cash flow that should potentially offset in later years.

Yes, no, I think you have it right, Rob. Obviously at Nova Scotia Power, any incremental fuel costs that we would have incurred to date, wouldn't get trued up with customers until a future period. So that's really it was referring to. Tampa Electric, you're right, we had a midcourse correction. But even with that, we're seeing we're still seeing a little bit more under recovery on fuel that will all get trued up likely early next year. And we're still working through the timing of the regulatory filing on that, but by far and away, our experience this year has been New Mexico that you highlighted.

Thank you. That's it for me.

Thanks, Rob.

And your final question comes from the line of Andrew Kuske of Credit Suisse.

Thanks, good morning. I guess it starts off with Greg, is even by CFO standards you mentioned balance sheet a lot on this call and not sure trying to be patronized about it. But you've come a long way in the last few years. But where do you ultimately want to wind up?

I'll take that as a compliment, Andrew, thank you. So we're happy. Look, we you're right, we have done a lot of work. We've done a lot of work with the asset sales that we completed a little over a year ago with the sale and remained happy with the outcome of that. I've continued, I think very methodically raised the appropriate amount of equity through our ATM and drip programs. And then of course, this year, we're happy with the successful execution of a couple of preferred share offerings. So I'd say we're happy with where the balance sheet now, obviously, the last 12 months or so, we've been focused on the cash flow. And that's why the three rate cases, the two gas utilities last year, and by far and away, the largest at Tampa Electric this year, was a priority for us. We are happy with the outcomes of all those. So I'd say from a balance sheet perspective and a credit metric perspective, we feel like we're in pretty good shape. But I don't want anyone if we mentioned it more than you would have expected is we don't want you to be left with the impression that it's not still an area of focus, at least for me and my team, because it is.

That's helpful. And you could take it as a compliment. But the dynamics that you face right now you've got, as with a number of others in the industry, like a tremendous amount of growth opportunities within the rate base and doing more creative things like Atlantic Loop. How do you think about the funding of that? And is there a way that you could use securitization mechanisms as we've seen these in the past? And, even currently in place in some areas in the U.S., does that sort of fit into the equation of part of the funding solution?

Yes, I think at this point is probably premature to, to comment on that, Andrew. I'd say, the capital in front of us. And we'll be rolling that forward in a couple of weeks. For you all to have some visibility on I would say we're, it's kind of normal course, business for us. It's, it's working our way through the capital structure, maximizing our operating cash flow, obviously, debt at the utility level. And then, preferred shares and common equity to balance that off, as long as we're inside our targeted capital structure. As we look forward, if we see a significant change in our capital investment opportunities, things like the Atlantic Loop, which again, it's a little bit premature, then we'll look at all sorts of opportunities, whether securitization on retiring coal plants, continually look at our portfolio to see if there's things that we can optimize our raising of equity and in a more cost effective way. But I'd say at this point in time, all of that's premature, until we have a sense of what that capital profile looks like and what the funding requirements from Emera will be.

Okay, that's great. Thank you very much.

Thanks Andrew.

And your next question comes from the line of David Quezada of Raymond James.

Thanks, Morning, guys. Just, just a quick one for me. Just curious, your thoughts on the various, I guess, clean energy incentives in the infrastructure plans that are being floated in the U.S. right now? Curious how you see that evolving in terms of your CapEx plan? Maybe this is pre-empting, your investor day a little bit, but I guess certain things like RNG and I guess potentially further tranches of renewables, how you see those playing roll? I guess RNG more, more specifically, going forward?

Yes, David look, I think, in a way it was a bit what I was trying to get at, in my remarks where, we've been, we've been focused on decarbonizing for a long time, as you know starting with a journey here in Nova Scotia, because Nova Scotia has generation profiles not that long ago was 90%, very high carbon emitting sources. And so, we're now in a place where we've got government policy that is advocating for in some cases mandating a faster and more accelerated pace to decarbonize. And so to the extent that there is government support for this in the form of tax credits or subsidy, frankly it helps because, one of the challenges in this is, is not the ability for utilities to execute. And even for that matter fund, the capital plans relating to decarbonizing, it's doing in a way that that still keeps it affordable for customers. And the fact is, all else being equal, the faster you do it, the more it costs. And so, to the extent that there's there's government support through policy initiatives that seem to be in focus in both, both the U.S. and in Canada. Frankly, that's just at least directionally helpful, because it allows us to execute and reduce the cost pressure that that acceleration has on customer rates.

That's great color. Thanks Scott.

There are no further questions at this time. I would now like to hand the call back over for closing remarks.

That concludes our call today. Thanks very much for your interest.

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