David Chong - Director of Finance Mark Collin - Senior Vice President and Chief Financial Officer Robert Schoenberger - Chairman, President and Chief Executive Officer Tom Meissner - VP of Technology Solutions

Insoo Kim - RBC Capital Markets, LLC

Good afternoon and thank you for joining us to discuss Unitil Corporation's third quarter 2017 financial results. With me today are Bob Schoenberger, Chairman, President and Chief Executive Officer; Mark Collin, Senior Vice President, Chief Financial Officer and Treasurer; Tom Meissner, Senior Vice President and Chief Operating Officer; and Larry Brock, Chief Accounting Officer and Controller.

We will discuss financial and other information about our third quarter and year-to-date results on this call. As we mentioned in the press release announcing the call, we have posted that information, including a presentation, to the Investors section of our website at www.unitil.com.

We'll refer to that information during this call. Before we start, as you can see on Slide 2, the comments made today about future operating results or future events are forward-looking statements under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.

Forward-looking statements inherently involve risks and uncertainties that could cause our actual results to differ materially from those predicted. Statements made on this call should be considered together with cautionary statements and other information contained in our most recent Annual Report on Form 10-K and other documents we have filed with, or furnished to, the Securities and Exchange Commission.

Forward-looking statements speak only as of today, and we assume no duty to update them. With that said, I’ll now turn the call over to Bob.

Thanks, Dave. Good afternoon, everyone.

This morning, we announced third quarter earnings of $0.16 a share, $0.09 lower year-over-year. Primarily causes were milder summer weather and higher O&M.

We also announced a nine-month earning of $1.27 a share, up $0.06 or 5% year-over-year. Primary causes were continued strong economic growth in our service territories and our positive regulatory agenda.

We are pleased with the progress we've made in Sanford and Saco with our TAB program. We have the potential to add up to 3,000 new customers in these towns.

We're also looking for additional ways to grow our gas business. For example, we are developing, what we call, a fill-in strategy that allow us to serve areas, such as in South Portland, which, for one reason or another in the past, did not have access to natural gas service.

Finally, this year, we have filed for almost $11 million of rate relief in New Hampshire and Maine in our gas business. We expect rate decisions on both those cases next year.

And then, finally, we continue to participate in grid modernization dockets in both New Hampshire and Massachusetts. We expect these kinds of investments to be an important part of our capital spending in the years ahead.

I'm going to turn the call over to Tom, who will describe our construction activities.

Good afternoon, and thanks, Bob. I just was going to focus on some of the key highlights, starting on Slide 6.

Some of these Bob touched on, so I won't cover those again. But I did want to mention our pipe replacement and upgrade programs in all three states.

Our gas pipe replacement programs are making good progress. Our New Hampshire program is expected to be completed this year, in 2017.

In Maine, our gas infrastructure replacement program is on schedule to be completed by 2024 and our Massachusetts program is a little further out, with the anticipated completion of less than 20 years. All of these programs have been supported by our regulators, and we have established ratemaking mechanisms in each state.

As a result of these infrastructure replacement and improvement programs, our customers are currently enjoying one of the most modern gas distribution systems in the regions. On the electric side, we're pleased with our two recently completed electric substations in New Hampshire, which were a combined multi-year investment of about $25 million.

These substations provide the capacity needed for continued load growth and reliability while also addressing constraints at our existing substations. With regard to solar, work is nearly complete on our 1.3-megawatt solar generation facility in Fitchburg.

Construction of this $3.5 million facility is on schedule to be completed next month. With that, I'm going to turn the call over to Mark Collin, who will discuss our financial results for the quarter.

Thanks, Tom, and good afternoon, everyone. Turning to Slide 7, natural gas sales margin was $75.3 million in the nine months ended September 30, 2017, resulting in an increase of $3.6 million or 5% compared to the same period in 2016.

Total therm sales for the year are up 4.9%, driven by customer growth and colder winter weather compared to prior year. Residential sales are up 9.8% in the first nine months of the year, and the total number of natural gas customers we are now serving is up approximately 1,200 in the last 12 months.

If we turn to Slide 8, electric sales margin was $70.1 million in the nine months ended September 30, 2017, resulting in an increase of $4 million or 6.1% compared to the same period in 2016. Electric unit sales for the year were down 2%, driven by ongoing energy efficiency initiatives and milder summer weather compared to the same period in 2016.

However, we are also seeing strong growth in our electric customer base, which is up by more than 1,000 customers in the last 12 months. Turning to Slide 9, we have outlined the major expense variances year-to-year.

Operation and maintenance expenses increased $4.4 million for the nine months ended September 30, 2017 compared to the same period in 2016. This reflects higher compensation and benefit costs of $1.1 million and higher utility operating costs of $3.3 million.

In utility operating cost is included a $1.5 million of higher vegetation management costs, which are recovered in reconciling rate adjustment mechanisms and reflected in electric sales margin as we have discussed in the past. In addition, also included in utility operating costs are higher regulatory commission costs of $0.7 million.

These are also reflected in costs reconciling rates and higher – and are, therefore, shown in margin – or offset in margin. The higher maintenance costs are – make up the remainder of $1.1 million.

Excluding costs reconciling vegetation management and regulatory commission costs, O&M was up about 4.5% year-over-year. Depreciation and property tax expenses are higher due to our continued growth in our investment in utility plant.

This will be a continuing theme as we grow our rate base in the future. Amortization expenses in 2017 also reflects lower amortization of major storm costs, which were incurred in prior years and deferred for rate recovery and are now reaching the end of – and are fully recovered.

Net interest expense increased $0.4 million in the first nine months of the year compared to the same period in 2016, reflecting higher levels of short-term debt in support of our capital investment, partially offset by higher net interest income on regulatory assets or liabilities and repayment of higher-cost long-term debt. Now turning to Slide 10, we take a look at our historical return on equity and regulation.

We have a constructive regulatory environment that is supportive of investment and growth initiatives, which improves the reliability and safety of our services to our customers. Earlier this year, we filed base rate cases for the Maine and New Hampshire divisions of one of our gas utilities for a combined rate increase of about $10.7 million.

These filings also include proposals for comprehensive long-term rate plans, which will allow for more timely recovery of portions of our capital spending on our gas distribution system. In the New Hampshire gas rate case, we were awarded a temporary rate increase of $1.6 million, effective August 1 of this year, which will be reconciled to the permanent rate level to be decided in early 2018.

Slide 11 provides an update on our long-term financings. Earlier this year, three of our regulated utilities entered into agreements to issue and sell a total of $90 million of senior unsecured notes through a private placement marketing process to institutional investors.

We anticipate closing and funding these long-term financings next Wednesday, or November 1, 2017, with net proceeds from the offerings to refinance higher-cost long-term debt maturing later in 2017 and repay short-term debt and for other general corporate purposes. Now turning to Slide 12, here, we strive to achieve a balanced capital structure with strong equity capitalization.

We were recently issued a Baa2 rating at the parent level and a Baa1 rating across our distribution utilities. This Moody's rating, combined with our Standard & Poor's issuer rating of BBB+, exhibits our strong investment-grade level and commitment to a balanced capital structure.

Now turning to Slide 13, as we do each quarter, we have again provided an update on our financial results at the utility operating company level. Chart shows the trailing 12-month actual earned return on equity in each of our regulatory jurisdictions.

Unitil Corporation, on a consolidated basis, earned a total return on equity of 9.6% in the last 12 months ended September 30, 2017. I would like to point out that these results are not weather-normalized.

Also, as we've discussed in the past, and as shown on the table on the right of the slide, we have long-term capital trackers in place to recover a significant portion of current and future capital spending. These capital trackers, coupled with sustained customer growth, help us maintain and stabilize the level of earnings across our utility subsidiaries and earn our authorized rate of return.

Now this concludes our summary of our financial performance for the period. I will turn the call over to the operator, who will coordinate your questions.

Thank you.

Hey, good morning and good afternoon guys everyone.

Hi, Insoo.

Good afternoon.

Just first on the solar strategy that you guys talked about at the beginning of the call. Could you just detail that a little bit more and, potentially, what kind of scale you're looking at?

Or maybe it's just more incremental in nature.

Well, again, we're in the process of developing it. But you take South Portland as a case in point, and you look at where our pipes are, and then you'll realize that there are parts of that city that are under or unserved because they really haven't had access to a natural gas service in the past.

So we're in the process now, we're doing sort of like what we did with our TAB program, identifying those areas and then prioritizing how we might approach them.

And how does this fill-in strategy kind of lead to a potential expansion of the TAB program that you guys did in Sanford and the other city?

Hi, Insoo, this is Tom. The way it's envisioned is if we identify an area that's not currently served using similar assumptions to the TAB program, we're going to evaluate customer density, number of commercial customers that have passed our screens, and then we would go ahead and lay mains on that area, with the intention of serving that area that's currently unserved.

Typically, just to add a little more, Insoo, this is Mark. Typically, the fill-in strategy isn't as geographically wide or as broad an area as the TAB.

It is more – that's why we use the term fill-in. It's usually surrounded by areas we're already serving and is an area that is – could be attractive economically and quickly serve off our existing pipe system with minor additional mains or minor additional reach.

And so again, the unique nature of the development of our service territory and – here in Northern New England and particularly in Maine versus the rest of the country, there's just hasn't been the same penetration, not only of customers on the gas system but the gas system itself wasn't fully developed throughout given franchise areas. So we're taking a real hard look at that and seeing if there's just groups of customers, smaller groups in the TAB, the groups of customers we can go grab in an economic basis without needing special rate surcharges or any kind of special ratemaking but just more of a prioritizing.

Moving a little bit off – now we're focused on the Maine, obviously, getting that fully subscribed. But now this is an opportunity to branch out a little bit.

Insoo, we've talked about this before. To put this in perspective, because of the growth we've seen in programs like the TAB, you would expect, over time, that our penetration rate would start to rise.

But because of this growth, our penetration rate is still only about 60%.

System keeps getting into new areas that are underserved or not served at all.

Got it. That makes sense.

Okay. And then maybe turning to the Northern Utilities rate case in Maine.

Are you guys hoping for settlement this time around as well? And if so, around what timeframe could we expect it by?

Yes, I don't know if hoping is the word we use. We're always open to settlement on issues and going to the rate case with making sure that we have a full support for our case and field it if it does go all the way to the litigation that we can support it.

On the other hand, as I said, we're open to settlement, and we'll do that. The final order – whether we settle or whether we go through a litigation process, I don't think it'll change the timing.

They usually use their full statutory review period which is, in Maine, it's about 9 months. So we expect an order in February, and I think that's when we'll get it.

Got it and then I know you've talked in the past about how the growth in your electric territories have been outpacing the gas side. At what point do you expect that to materialize into potentially an upward movement of that 4% to 6% forecasted of rate base growth?

I think, if you're looking at the electric rate base growth and seeing that notching up a little bit, the customer growth will help that, and there will be some uptick in that. I think we'll be seeing it in 2018 even because – just because of the economy, the number of customer hookups are accelerating.

But the real impact on our electric CapEx growth and investment growth is going to be the grid modernization program in both Massachusetts and in New Hampshire. And we're a little further along in Massachusetts, and we're talking about $25 million, almost $25 million over 10 years there.

And if you size that for New Hampshire, so we do a similar program in New Hampshire, that's going to probably add another $60 million in New Hampshire or so. So the two of those together is a substantial amount of additional capital expenditure above $80 million, $85 million over the next 10 years associated with the program that have strong regulatory support, good cost recovery and has a very specific mission and goal in achieving modernization of the grid and I think that, more than anything we've seen on the horizon right now, will be the most – will push up our growth in our rate base on the electric side.

Okay. So that's basically saying the grid mod in both Massachusetts and New Hampshire are – would be incremental to the rate base growth that you guys currently are forecasting?

Yes.

Okay. And then in terms of timing on the grid mod, I know the $24 million had been identified in the past.

That process, I believe, late this year, was one that was supposed to be concluded in terms of an approval. Have we – what's the latest on that?

We're still expecting the Massachusetts piece of $25 million, if you will, for Fitchburg to be – get an order anyway in the fourth quarter here, yes.

Got it. Okay.

And then, finally, just on the dividend payout. I know you guys had in the past targeted a 70% to 75% target range.

Depending on where growth goes in the next couple of years, do you – are you committed to kind of staying within that range on a yearly basis? Or depending on the level of growth year-over-year, could that number fall potentially below the range for a year or two?

Insoo, our goal is to be between 70% and 75%, so that hasn't changed. Obviously, it'll be reviewed every year.

But that goal hasn't changed.

Understood. All right, thank you very much.

End of Q&A