Eversource Energy (ES) Earnings Call Transcript & Summary

Good morning, everyone, and thank you for joining us at the fifth annual JPMorgan Energy, Power and Renewables conference. This morning, we're extremely excited to start off with Eversource. We're glad to have Jeff Kotkin here to walk through the Eversource story. After that, there will be a time period for questions, where I'll ask questions, and the audience can also contribute questions as well through the website. So looking forward to that. But turning it off to start off here to Jeff. Thank you, Jeff.

Jeremy, thanks so much for having us and for allowing us to participate in your conference. So greatly appreciate it. For folks who are on and who are not familiar with the Eversource story, we are the largest utility in New England. We have -- we're about 85% electricity, 11% natural gas and about 4% water. We're the only electric utility in the country that also owns a water utility. We bought Aquarion about 2.5 years ago. And we are now -- and we'll get into this a little bit. We're now also in the process of buying the natural gas asset in Massachusetts from that belong to Columbia Gas part of NiSource. So we distributed a slide deck, and I'm going to go through that slide deck a little bit as we go forward. And then after about 15 or 20 minutes, I'll turn it back to Jeremy for questions and answers. But if we go to Slide 2 on the deck, if you take a look -- just a little bit about how we've been doing during the COVID crisis over the past 3 months, our key -- the key focus for us is to keep our employees safe and to keep our customers safe and to continue to deliver vital products and services to our customers, and we succeeded in doing that. We have about 8,300 customers -- excuse me, 8,300 employees, and about 4,500 of those employees work in the field. They work on the pipelines. They work on the substations, they work on the lines. They supply the trucks, they would maintain the trucks that go out into the field. And we've basically not missed a beat in terms of providing the service to customers. We've had a few weather events over the past couple of months, a late season snowstorm in New Hampshire that caused about 56,000 power outages and then a severe windstorm in Southern New England in the middle of April. But even with those events, we organized very well, and we had almost all customers back in the first 24 hours. Also worth noting is just like many other -- or most other utilities around the country, we have a moratorium on customer shutoffs in all states, unless there's a safety issue. So we've been working closely with our customers to make sure that we can support them through this period of time. And we've had very, very positive feedback from customers during this period. So turning to Slide 3, a little bit of background. So Eversource, again, is a delivery company. We don't own any generation other than about 70 megawatts of solar generation that we built on a one-off basis in Massachusetts. That's all rate based. So we deliver electricity. We maintain the transmission and distribution systems. We maintain gas distribution. We don't have investments in gas transmission, and then we also distribute water as well. And the company has done an excellent job since the merger that created us a little over 8 years ago in terms of improving service, building out our system and reducing our operating costs. And that's been reflected in our share price and total return performance, which you can see on Slide 3. So whether you're looking at this year through May 31, or last year or the 3- or the 5-year or 10-year, we've solidly beaten both the EEI 40 company index as well as the S&P 500. And again, I think this is a real -- this is really due to our focus on execution and supporting our customers and also maintaining our costs and building out systems that are required to provide safe and reliable service to our customers. So let's move on to the next slide. Our guidance for this year, which we established back in February was $3.60 to $3.70 a share. The mid-point of that is somewhere around 6%. And if you take a look at the long-term earnings growth of the company since we were created by the merger of Northeast Utilities and NSTAR in April of 2012, earnings growth has been right around 6% on average over that period of time. And our long-term growth estimates from our core business -- and it's important to note, our core current core business is 5% to 7%. So I think a lot of The Street is looking at earnings growth over the next 4 to 5 years of somewhere around 6% a year, which is consistent with our long-term growth estimate. The key to earnings drivers this year are distribution rate increases, our 2 largest -- actually, our 3 largest distribution companies by rate base, all are operating under long-term rate plans. They're about halfway through them. This is Massachusetts Electric, Connecticut Electric and Connecticut Gas. The 2 underperformers among the group, which are Massachusetts Gas and New Hampshire Electric are in for rate cases, and they should be receiving rate increases later this year, towards the tail end of this year. So not really enough to drive 2020 results, but they could certainly help 2021 results. The other driver is transmission rate base growth. We have a $1 billion capital program in transmission again this year. And also in several areas on the distribution side, we have certain capital tracking programs where if we make investments in something like replacement of older pipe on our gas distribution system, we're able to immediately reflect that in rates. Now the flip side is that as you're building out your system, you have higher depreciation expense, higher property tax expense, higher interest expense. And also, we've not -- we can't finance all this development solely through internally generated cash and borrowings. So we have been issuing some additional shares over the past year or so. So we do have a higher share count as well. So that somewhat offsets higher earnings. Switching to Page 5. If you take a look at that, basically, what we say is we're going to grow the dividend in line with earnings growth. So if we say that the core business is going to produce 5% to 7% earnings growth, then we say that the dividend is going to grow 5% to 7%. You could see on this chart that has been, we just raised the dividend 6.1% earlier this year. And our payout ratio, which is now about 62% is -- I think it's a little bit on the low side among the larger regulated companies in the country. Turning to Slide 6. What's driving this growth is our capital program. So you could see that the capital program last year exceeded $3 billion for the first time. We expect it to slightly exceed $3 billion again this year. And even in the future years, it's sort of in that $2.7 billion, $2.8 billion range as we go forward. So basically, these are expenditures which have been reviewed by our regulators, either specific projects, larger ones are specifically reviewed by regulators. The more routine projects are reviewed basically as part of an overall program, and they're endorsed by the regulators. So these are all needed in order to connect new customers or to replace obsolete equipment. And as a company that serves an older part of the country, there is a lot of equipment that we continue to operate that is 50, 60, even 70 years old that we need to replace, and we've had an active replacement program for many of that -- much of that equipment lately. Diving down a little bit specifically in terms of some of the aspects of the business. On Slide 7, we talk about transmission rate base growth projections. So if I go way back to around 2004, 2005, that transmission rate base was probably not much over $0.5 billion. And if you take a look at us and much of the industry back in that -- in those days of 2003, 2004, 2005, the industry from the late '70s until that period had really underinvested in the transmission systems. They invest in new generation, invested in distribution systems, but really had underinvested in transmission. And it was apparent back in the year 2003 when we had a major blackout that started in Ohio and spread to parts of the northeast that the transmission system really was overburdened. So if you may recall, back in 2005, the federal government basically said, "look, this is a big problem that there hasn't been enough investment in transmission." And that mistake in operating the transmission system could cause such a large blackout. So they basically passed, as part of the Energy Policy Act, a series of carrots and sticks that FERC can make available to transmission owners. The carrots are that if you invest heavily in your systems, you can get additional returns on equity or additional cash flow while you're building it beyond what was standard, I guess, at that time. The sticks were that if you didn't operate your system well, you could be hit with multimillion-dollar fines. And there have been some utilities that have the hit with fines over the years. We've not been one of them. But what's happened is this intense investment in transmission has really strengthened the system, made it more modern, made it more durable, and it's also grown the system. So you could see that as of the end of last year, we're just -- we had just under a $7.3 billion transmission rate base at our 3 core electric companies, again, compared with something on the order of maybe $500 million or $600 million 15 years earlier. That's what's grown transmission earnings significantly. Transmission earnings were in the $30 million range, perhaps back then, and now they're well over $400 million a year. Turning to the gas side. We still have a lot of older pipe on the system. This is cast iron pipe, unprotected steel pipe. And the regulators have endorsed getting that pipe out of the ground because that pipe just tends to be -- may only be 15% or 20% of the system, but they probably account for 80% or so of the leaks on the system. So we've had an active program to remove that pipe. It's probably doubled in both Connecticut and Massachusetts over the past several years, and we have trackers for that. And that's one of the primary drivers of the size of the gas business. One is pipe replacement, a very active and aggressive pipe replacement program. We should be done, getting out the old pipe in Connecticut in the next 8 to 10 years. Massachusetts, where there's more, it's probably more like 15 or 20 years. The other thing on the gas side is that we continue to add customers at a rate of about 2% a year. And this customer growth is a combination of people who were switching over from oil. Oil remains the largest source of space heating in New England, but a lot of customers would like to have a gas furnace in their basement rather than an oil furnace because it's cleaner, it's cheaper, it's easier to maintain. So we probably got about 5,000 conversions a year and probably 5,000 or 6,000 new customers where there's new construction going on. So we're probably adding 10,000, 11,000 customers a year on the heating side. And if you think about that, that's about a 2% annual customer growth on the electric side where basically, everybody gets electricity. That growth is more in the order of perhaps 0.5% to 1% a year. On the water side, we bought Aquarion a few years ago. It had been owned by a private equity shop. It's a great company, but there probably was insufficient amounts being invested in the business prior to our acquisition. And we've stepped up the rate of pipe replacement. Again, this is water, not gas pipe, but water pipe replacement and some other steps. Much of Aquarion is based in Western Connecticut. In fact, 90% of all Aquarion is in Connecticut, the remainder in Massachusetts and New Hampshire. And we not only need to replace pipes, which have been in the ground maybe for 100 years, and in some cases, has leaking water. But we also need to supply -- provide additional supplies to Southwest Connecticut, far Southwest Connecticut, lower Fairfield County, where we don't have adequate supplies currently, and we're working to bring supplies from the Bridgeport area where we have excess water down to that area. So that's part of that capital program and rate base growth that you see on Slide 9. When you put it all together and you look at Slide 10, you can see that our a CAGR for our rate base is 6.9%. You could say, well, if you're growing your rate base by 6.9%, why aren't you growing your earnings by that level, why are you growing your earnings more than the 5% to 7% range? And the answer is that we do have additional shares that we need to issue. We sold $1.3 billion of stock last year. And that was to help finance our capital investment program. And just yesterday, in fact, we closed on an additional 6 million shares. That, however, is not for the core program, it really is for the acquisition of Columbia Gas of Massachusetts assets. So if you take a look at Slide 11, you could -- if you look at the blue, Columbia Gas is actually a somewhat larger system in Massachusetts than NSTAR Gas. It serves about 330,000 customers. NSTAR Gas serves about 300,000 gas, Yankee Gas about 250,000. But if you look at -- if you have the map in front of me, and you take a look at it, you could see that the 2 largest parts of the service territory of Columbia Gas in Massachusetts, largest is just south of Boston. And it's basically surrounded by to the northeast -- excuse me, the northwest and the southeast by NSTAR Gas service territories. It's also an area where we serve a lot of those towns with electricity. And then if you look at Western Mass in the Springfield area, that area [ above ] the Yankee Gas service territory in Northern Connecticut. And again, we serve the Springfield area with electricity. So there's a lot there's a lot of sense of bringing Columbia Gas in. If you take a look, you can see that we have now financed the equity associated with the acquisition. The acquisition is $1.1 billion in cash which is about rate base. We're basically paying 1x rate base. There's no assumption of debt, so there will be additional debt that we will sell initially at the parent company. That will probably be closer to closing, which we expect will be somewhere around the end of September. And we expect the acquisition to be accretive over the first 12 months and then incrementally more accretive over the following years as we migrate some of the systems like payroll and accounts receivable and gas dispatch. As we migrate those systems from the NiSource systems over to the Eversource systems there will be additional savings as we move forward. So that will help create additional earnings as we move forward in addition to the money that we expect to invest in the Columbia Gas system. The key approval that we still have is the mass DPU. We should be filing that later this month, and we're looking for approval by the end of September. Some folks have said, well, what would be additive to the core business forecast, grid modernization in Connecticut and in New Hampshire would be one thing. And Connecticut is looking right now at a series of potential initiatives and they're looking for proposals to be filed by the end of July. One of them would likely have to do with AMI but there's also additional capital that we expect to invest in the natural gas systems of our existing subsidiaries and Columbia Gas as we go forward. One piece -- one thing that's worth noting is that we don't have any -- we own no emitting generation. We have some of the best and most aggressive energy efficiency programs in the country in terms of helping our customers use less every year, particularly on the electric side, where even though the number of customers is going up by 0.5% to 1% a year, the customer usage is going down by about 1.5% a year. And a lot of that is just due to the energy conservation programs that we promote among our customers. We spend over $0.5 billion a year on those programs. So we -- and this is all with the support of our regulators who say, "Look, we are going to decouple your rates from volumes. So you're going to be guaranteed a certain amount of revenue per year." And we basically said, "That’s great." So we're not going to cannibalize ourselves by promoting these energy efficiency programs. So we have energy efficiency. We are promoting offshore wind, we're converting folks away from oil. So all of -- and we're replacing pipe, all of this is part of our goal to become carbon neutral by 2030. And that's the most aggressive timetable of any utility and electric or gas utility in the country, and I feel sort of privileged to be part of the steering committee for that effort. One last thing worth noting is that we also are partners with Orsted in terms of building out offshore wind in the Northeast. We have contracts for 1,714 megawatts. 2 applications are now pending with the federal government. The third Sunrise Wind, which is the largest will be filed probably around the end of the year. And we look forward to building out this offshore wind business, which we think makes a lot of sense for the states of Southern New England as well as for New York. So we think it's a growth business. We would hope that if we had this conversation 6 to 10 years from now, we'd be able to tell you about 4,000 megawatts of offshore wind that we're going to partner with Orsted on. So with that, I think I'm going to sort of end my comments and I'm going to turn it back to Jeremy.

Thank you, Jeff. Really appreciate you walking through the Eversource story here. That was very helpful. We do have a question from the audience I want to lead off with here. And I was just wondering -- and I think this is with regards to COVID-19 and how that impacts Eversource. The question more specifically would be, "can you talk about the latest trend you are seeing in terms of customer bill payment and any signs of delay?"

Good question. It's -- we really haven't seen much yet, honestly, in terms of delays, in terms of revenue coming in. Now mind you, it's really only been 3 months now. And you're also -- we're also dealing with a part of the year that energy use is the lightest. So if you look at April and May, those are like 2 of the lightest used energy months of the years, bills tend to be fairly low in those months anyway. So in terms of payments, we really haven't seen much. In terms of sales, there's definitely been a drop in commercial sales. I mean we don't have a big industrial sector. There's definitely been a drop in commercial sales and an increase in residential sales. For most, it hasn't been hugely dramatic, honestly. And interestingly, the part -- the one part of our service territory, where we don't have full revenue decoupling is New Hampshire, and New Hampshire has been far less affected by COVID-19 than the rest of the service territory. So where we did come up a little short in New Hampshire in the first quarter really was not related to COVID-19. It was a fact that all 3 months in the first quarter were 5%. The heating degree days were like 5 degrees below normal over the course of that period, which is huge. So we definitely lost a little bit of revenue to the weather, probably not that much to COVID-19.

Great. And then just kind of building on COVID-19, I guess, here. Do you sense any hesitation from the commission to implement rate increases coming out of the pandemic here? Or do you have a sense for, I guess, sensitivity of customer bills at this point given the backdrop of pandemic?

So we -- again, our larger subsidiaries are on these longer term rate plans, and we had a couple of Yankee Gas and NSTAR Electric, those rate increases go into effect in the -- at the beginning of the year, CL&P put its third of 3 fixed rate increases in effect on May 1. So no change there. We do have those 2 rate cases ending, one in New Hampshire and one at the gas subsidiary in Massachusetts. They won't be decided until the end of October for the gas company and probably late November for the electric company. So I guess, we'll see, but there's a lot of offsets and bills that are happening with customers, mostly on the generation side. The price for capacity in New England is going from about $4 billion to less than $1 billion. That hits the 7 million electric customers in New England. So they're seeing the capacity costs drop a lot. Gas prices are low, that we're looking at like $0.01 or $0.02 lower cost for energy this summer than it was last summer. So I think that total bill that the customer is looking at really hasn't changed much whatsoever. So the answer is no. And we can have -- continue the conversation after we get our rate case decisions.

That makes sense. Maybe just continuing with customer bills here. Just wondering what you think the potential longer-term impact of offshore wind could be? Do you see any kind of pressure on bills at that point? Or any thoughts you could share on that?

Sure. So New England is very, very focused on carbon reduction. We talked about it earlier, but all the states in New England are looking at reducing their carbon footprint by about 80% over the next 30 years or so which is enormous. I mean, if you think about it -- and a lot of it has -- doesn't have anything to do with electric bills. A lot of -- transportation is, by far, the leading source of carbon emissions in the region followed by space heating and then electric generation is actually pretty low, elsewhere in the country it could be up to 40% or 50%, New England is at 16%. I think the states have understood that whether they promote offshore wind or they promote solar, at least in the short term, that will have inflationary impact on bills, but their view is that the environmental issues are very important. And over the long term, leading the region off of fossil fuels will have cost benefits as well. So I've been in New England on my whole life. Every time a legislator touches an energy issue, they tend to increase the targets rather than decrease the targets. So I don't see that changing, honestly. And honestly, to tell you the truth, solar has been a much bigger impact on bills particularly in Massachusetts than anything else.

Yes. That's helpful. And another question from the field, sticking with wind here. What is your assessment of BOEM SEIS on Vineyard Wind project that was issued last week?

Sure. So Vineyard Wind is 50% owned by Avangrid and 50% owned by Copenhagen Infrastructure Partners. If you look off the coast of New England, we and Orsted have 2 of the 6 tracks that have been bid out. Vineyard Wind has 2 others, and then the others are owned by Equinor and a partnership with Shell. But what BOEM, Bureau of Ocean Energy Management, which is part of the Department of the Interior, they are the lead federal agency in terms of selling off these tracks and then licensing the offshore wind. So what they did as part of the Vineyard Wind application was they took a look at a lot of these tracks and even more actually further down the Atlantic seaboard to see what the cumulative impact of all these tracks being developed would have. And one of the things that we were pleased with is that they recognized that the developers of the [ areas off of ] Massachusetts, we all agreed to line up our turbines 1 nautical mile apart north to south and east to west. So that if a boat or the Coast Guard needed to traverse these tracks, they could go east, west -- regardless of who owned it, they can go east west from one end to the other and north-south from one and the other. Without having to worry about having a zigzag depending on who owns the tracks, and they also found that the mile -- 1 nautical mile spacing helped preserve marine safety. So that was recognized in the supplemental report as being a positive for the projects. I think we're now looking at other items in there. I mean there's a whole lot of like 20 different areas we're BOEM looked at. And we're trying to look at what they want, what their concerns are, where they think the big impacts are and what we've already pledged to do to mitigate those concerns. And as we -- we'll continue to go through it to try to figure out whether or not there's any changes in our applications that we would have to make. But first indication, we're fine. But we're going through a lot of the details, and we really haven't -- it's a 420-page report. Note, we can't make a definitive statement about 420 pages yet.

That makes sense. That's helpful. And maybe try to sneak one more last question in before we run out of time. Just want to -- if you could comment more, I guess, on transmission sufficiency in your neck of the woods in D.C., an opportunity for larger transmission build out over the next 5 or 10 years or so?

I don't think there's going to be big projects. We're wrapping up a few big projects right now. We just wrapped one up in New Hampshire a few weeks ago. We have two in Connecticut that will finish of this year. These are in the hundreds of millions of dollars. And one in Massachusetts, it's like 30 different parts to it, but the last part of it has gotten a bit delayed. It probably won't be finished for a couple of years or so. I don't see another big leg of large projects after that. I think a lot of it's going to be -- where there is load growth, you're going to have to build more capacity and where you have very old structures or equipment, you're going to have to replace it. Maybe way, way down the road with a lot more offshore wind coming in, you're going to have to somehow supplement the transmission in southeastern New England, but it's pretty robust right now. So I don't see that happening in the real near term.

Great. That's very helpful. And we would just want to say thank you again, Jeff, for joining us and going through the Eversource story. Thank you, everyone in the audience for joining us as well and looking forward to seeing Eversource again next year at the conference.

Thank you.