Unitil Corp (UTL) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q2 2017 Unitil Corporation Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded. I would like to introduce you host for today's conference, David Chong. You may begin.

Good afternoon, and thank you for joining us to discuss Unitil Corporation's Second 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 second 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 will refer to that information during this call.

Before we start, as you can see on Slide 2, any of the comments made today during the presentation 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 will now turn the call over to Bob.

Thanks, David. Good afternoon. The company had another great quarter and first half of 2017. This morning, for the quarter, we reported earnings per share of $0.23 a share or $0.05 higher year-over-year.

For the first half of the year, we reported earnings per share of $1.11, up $0.15 or 16% year-over-year. The company continues to operate on all cylinders. We had a very busy regulatory agenda during the quarter, and Mark will go into detail on those activities.

The Maine Commission approved our second TAB program for Sanford, Maine. Between Saco and Sanford, our first 2 TAB programs, we expect to add over 3,000 customers over the next 3 years.

And then finally, we have begun construction on our 1.3-megawatt solar facility in Pittsburgh. We expect that to be online in November.

With those opening remarks, I'll turn the call over to Mark.

Thanks, Bob, and good afternoon, everyone. I'm going to review our financial results at the halfway point of the year. You can turn to Slide 7 and take a look at natural gas sales margin. Natural gas sales margin was $58.5 million in the 6 months ended June 30, 2017, resulting in an increase of $2.8 million or 5% compared to the same period in 2016.

Total therm unit sales for the year are up 4.6%, driven by customer growth in colder winter weather compared to prior year. Residential sales are up 10% in the first half of the year.

We continue to see growth in our total number of natural gas customers, which are up by more than 800 year-over-year.

Now turning to Slide 8. Electric sales margin was $45.3 million in the 6 months ended June 30, 2017, resulting in an increase of $4.8 million or 11.9% compared to the same period in 2016.

Electric unit sales kilowatt hours for the first half of the year were down slightly on a total basis. However, residential kilowatt hour sales increased 2.1% in the quarter and 1.2% year-to-date. We are also seeing strong growth in total number of electric customers added, which are up more than 1,000 year-over-year.

We continue to experience the effects on unit sales of our very well-funded and successful utility-sponsored energy efficiency initiatives within our jurisdictions, which are obviously designed to reduce customer usage of energy. As a reminder, in New Hampshire, we have a loss-based revenue recovery mechanism that helps us recover loss-based revenues due to reduced sales resulting from our energy efficiency programs.

At our Massachusetts utility, we have revenue decoupling in place that eliminates the dependency of our distribution revenue on the volume of electric or natural gas sales. So reductions in sales do not affect income. We estimate that revenue decoupling applies to approximately 27% and 11% of our total annual electric and natural gas sales volumes, respectively.

Now turning to operation and maintenance expenses, they increased $2.1 million for the 6 months ended June 30, 2017, compared to the same period in 2016. This reflects higher utility operating cost of $1.7 million, including $0.8 million of higher vegetation management costs, which were recovered in electric rates and reflected in electric sales margin; higher regulatory cost of $0.6 million; and higher all other utility operating cost of $0.3 million; and higher compensation and benefit cost of $0.4 million. Excluding vegetation management cost, O&M was up about 3.9% year-over-year.

Depreciation and amortization and property tax expenses are higher due to our continued growth in the investment of our utility plant. This will be a continuing theme as we grow our rate base in the future. Net interest expense increased $0.1 million in the first 6 months and was down $0.4 million in the quarter compared to the same periods in 2016, reflecting an increase in interest expense on short-term debt in the 6-month period, partially offset by higher interest income on regulatory assets and lower interest due to the repayment of higher cost long-term debt.

On Slide 10, we provided an update of our rate case activity. In April, our New Hampshire electric utility received approval for an annual electric rate increase of $4.1 million as well as approval for a 3-year long-term rate plan to recover the revenue requirements associated with 80% of our annual capital spending.

This first step -- the first step adjustment of $0.9 million under this rate plan became effective May 1, 2017. The next 2-step adjustments under the rate plan are scheduled to follow on May 1 of '18 and of 2019.

In the second quarter, we also filed base rate cases for the New Hampshire and Maine divisions of our gas utility for base rate increases of $4.7 million and $6 million, respectively. These filings include proposals for comprehensive long-term rate plans, which will allow for a more timely recovery of portions of our capital spending on our gas distribution system.

In the New Hampshire gas rate case, the company has entered into a settlement agreement for a temporary rate increase of $1.6 million effective August 1 of this year. This will remain in effect and reconciled once permanent rate increase is decided. Final orders are expected to be issued in New Hampshire and Maine in the third and first quarter of 2018, respectively.

Slide 11 provides an update of a couple important regulatory proceedings for our electric business. We are actively engaging grid modernization initiatives in both our Massachusetts and New Hampshire electric subsidiaries with support from the regulatory commissions. At a high level, grid modernization is an effort to improve the reliability, resiliency and operational efficiency of the electric grid, while empowering customers to use their electricity more efficiently and facilitating the integration of distributed energy resources.

A 10-year grid modernization program with preliminary planned spending of $24 million is currently in the approval process in Massachusetts. New Hampshire's grid modernization plan is still subject to regulatory review proceedings and further development, and we expect an order in that proceeding by the end of the year.

We've also been participating in a net metering and distributed energy resources docket in New Hampshire. The purpose of this proceeding was to address net metering of distributed generation installations, including solar, and to address cost shifting occurring between distributed generation customers and nondistributed generation customers.

In June, the New Hampshire Public Utilities Commission issued an order in this proceeding. The order removes the current cap on the total amount of generation capacity that may be owned or operated by customers and it is eligible for net metering. The order also adopts an alternative net metering tariff for small and large customer generators that will remain in effect for a period of years, while further data is collected and analyzed.

The order is a step forward in the improvement from the previous net metering tariff. Overall, this order begins to recognize the cost shifting that is occurring and takes incremental steps to address this important matter.

Now turning to Slide 11 (sic) [Slide 12], I provided an update here of our long-term financings. Earlier this month, 3 of our regulated utilities entered into agreements to issue and sell $90 million of senior unsecured notes through a private placement marketing process to institutional investors. We anticipate closing and funding these long-term financings on November 1 of this year, with net proceeds from the offerings to finance higher cost long-term debt maturing later in 2017 and '18 and to repay short-term debt and for general corporate purposes.

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. The chart shows the trailing 12 months actual earned return on equity in each of our regulatory jurisdictions. Unitil Corporation, on a consolidated basis, earned a total return on equity of 10.1% in the last 12 months ended June 30, 2017. I'd point out that these results are not weather normalized. Also as we discussed in the past and as shown on the table on the right, we have long-term capital cost trackers in place to recover a significant portion of our 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.

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

(Operator Instructions) And our first question comes from the line of Insoo Kim from RBC Capital Markets.

Maybe starting with normalized gas sales. It seems like it was up pretty nicely this quarter. But looking at it on a year-over-year basis the past couple of years, it seems like it is still lagging historical growth levels. Is it still too early to see a, call it, trend in maybe saying the growth is a little bit slower this year than we've seen in the past? Or are there some other factors impacting it?

Yes, Insoo, I think probably to the contrary. I think what we're seeing now is -- because as Bob has talked about the pickup in economic activity that we're seeing in our jurisdictions in some of the major cities that we're in, I think we -- our expectation is that, if anything, the trend is starting to turn upward on both not only the gas side, where we did clearly benefit when there was a big spread between the gas -- natural gas prices and oil probably and got that extra kick, but now we're seeing it on both the gas and electric side. And I think, if anything, sales are trending up.

Okay. Understood. Regarding the new -- the Northern rate case in New Hampshire, has there been initial feedback from either the Commission or any intervenors regarding the long term, I guess, the multi-year plan in the base rate step-up?

It's (inaudible) it's pretty early in the process. As you know, and we talked about this as a long regulatory process in New Hampshire. It's over a year in duration from start to finish. So we haven't had a lot of discussion of the case in principle. I'll just say that this case follows a similar case that we filed a few years back, and we also proposed a rate plan there and were granted a 2-year rate plan. So we were able to do 2 step adjustments, as they refer to them in New Hampshire, following that rate case. We've asked for 3 here and hopeful that would allow us to stay out longer, avoid some of the cost of and the issues of putting on a full rate case. But -- and we're hopeful that we'll be able to convince the intervenors and staff to go along with that. But in any event, this is not rate plans or something that we have been successful at getting in the state. We continue to be hopeful we can get our plan as filed.

Insoo, I wanted to pick up on your growth rate question. I think it's instructive that for the second 12-month period year-over-year that we've added more electric meters than we did gas. So for example, over the last 12 months, it's about 1,100 electric meters versus 900 gas meters. And again, I think that just demonstrates what we've been telling our investors that this economic activity is spilling over to our electric business. In fact, if you take out the effect of energy conservation, that business is probably growing at an annual CAGR of 4% to 5%. If you compare that to an average electric utility company which -- lucky if they have flat to 1% growth.

Right. I do remember you talking about that with us and with investors, and definitely noted there. In terms of the net metering ruling, how does that impact or shape the state's renewable strategy, if at all? And what they're thinking about renewable growth going forward and how the limitation to the net metering rates, I guess, fits in with your overall strategy?

Yes. Let me have Tom Meissner kind of respond to that. He spent a great deal of time in the net metering docket and I think got a feel for its -- how important it is to the overall strategy in New Hampshire.

Yes, Insoo, I guess what I would say is I think the end result was somewhat of a compromise. Obviously, the state wants to continue to have clean energy and growth in distributed resources. So there was a desire to ensure that, that was going to continue. But at the same time, there's a desire to start to reform the rate design in the state and eliminate cost shifting or at least mitigate cost shifting between classes. So the result that was issued. On the one hand, there's going to be a continuation of monthly netting, which is really the big one in terms of the resources. But they're going to start to diminish the compensation for excess on a monthly basis, which we're hoping, in turn, will result in more realistic sizing of these resources.

And then does -- how did the state look at, I guess, utilities investments into renewables? Kind of similar to what Massachusetts is doing?

No. In New Hampshire, for the most part, we're barred from investing in these resources on our system. There is some limited application where we could, but it's so limited, it really doesn't make a lot of sense for the utilities.

Understood. Okay. And then maybe switching to grid modernization. The $24 million that's pending approval right now, if that were to be approved, what's the, I guess, investment per year that we could expect and for how long?

The $24 million was actually a 10-year figure, but it was front-end loaded in the first 5 years. So the first 5-year period would tend to be heavier, and I think on average would be on the order of $3 million to $4 million in each of the first 5 years.

Got it. And then in terms of rate making, is this a -- is there a tracking mechanism where you're just able to recover on a semi-contemporaneous basis? Or does this require investment and then you just have to go in for rate cases too?

In Massachusetts, there is a recovery mechanism for what they call the STIP, or the Short Term Investment Plan. So that is part of our plan in Massachusetts. In New Hampshire, it's too premature. We really haven't gotten to a point where cost recovery has been part of the discussion.

And that's important to point out that this $24 million is just with our Massachusetts electric utility. In New Hampshire, the amount would be in addition to that, and as Tom said, we're kind of in the early stages so we're reluctant to set a number on that or to confirm our cost recovery. But we'll be working through that over the next 6 to 12 months.

Got it. And finally from me, if I calculate correctly at the end of this quarter, your total debt-to-cap is just under 58%-ish level. When you're thinking about potentially equitizing the balance sheet, is it fair to target some kind of level in that 50% to 55% range that, I guess, from a regulatory perspective is what the commission typically looks at?

Yes. I think longer run, we try to target somewhere in the 50%, 55% range for debt-to-total cap, yes.

Thank you. And at this time, I'm showing no further questions over the phone lines. This concludes the Q&A session and today's program. Thank you for your participation. You may now disconnect. Everyone, have a great day.