Welcome to the Unitil First Quarter 2017 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to introduce your host for today's presentation, Mr. David Chong. Sir, please begin.

Good afternoon, and thank you for joining us to discuss Unitil Corporation's first 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, Chief Operating Officer; and Larry Brock, Chief Accounting Officer and Controller. We will discuss financial and other information about our first quarter 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. I'd like to give a few highlights of the quarter. First of all, this morning, we reported earnings of $0.88 a share, up $0.10 or 13% over the prior year, primarily because we had more normal winter weather this year compared to last year. At yesterday's annual meeting, we showed a video that we put together to detail the robust economic trends that we are seeing in our service territories, particularly Portsmouth and Portland. We fully expect that these trends will continue to allow us to grow our gas and electric business well into the future. On Slide 7, you can see our regulatory agenda, a very busy one. I won't go into a lot of detail, but just point out that we received approval from New Hampshire for new electric rates, and as well, we plan to file for new gas rates in New Hampshire and Maine during this quarter. On Slide 8, we are in the second year of our TAB program in Saco, Maine. We are very pleased with the results thus, far on that program. We have filed for a TAB program in Sanford, Maine, and we expect approval for that program shortly. Again, the TAB program is a really nice complement to allow us to continue our gas expansion program. Then finally, during the second quarter, we expect to begin construction of our 1.3-megawatt solar facility in Pittsburgh. The facility will cost approximately $3.5 million and will be in operation by the end of the year. With those kinds of highlights, I'll turn it over to Mark now who will discuss our financial results in detail.

Thanks, Bob, and good afternoon, everyone. I'll pick up on Slide 9. Natural gas sales margin was $38 million in the 3 months ended March 31, 2017, resulting in an increase of $2.1 million or 5.8% compared to the same period in 2016. Gas sales margin was positively affected by higher natural gas distribution rates, the positive impact of colder winter weather on sales and customer growth. Total therm sales of natural gas increased 3.6% in the 3 months ended March 31, 2017, compared to the same period in 2016. Based on weather data collected in the company's natural gas service areas, there were 5.4% more Heating Degree Days in the first quarter 2017 compared to the same period in 2016, which contributed a positive $0.03 to earnings per share. However, compared to normal, the winter for the first quarter of 2017 was about 9% milder than normal, which we estimate impacted EPS a negative $0.06. Turning to Slide 10. Electric sales margin was $22 million in the 3 months ended March 31, 2017, resulting in an increase of $1.9 million or 9.5% compared to the same period in 2016. Electric sales margin in the first quarter was positively affected by higher electric distribution rates and customer growth. Electric sales for the first quarter of 2017 were down compared to prior year by 1.2%, which we largely attribute to ongoing energy efficiency initiatives within our jurisdiction. Recently in New Hampshire, we successfully achieved a lost base revenue recovery mechanism which, starting this year, will help us recover lost base revenues due to lower sales resulting from our energy efficiency programs. For our Massachusetts utility, which represents about 27% of our electric sales, we have revenue decoupling, which eliminates the dependency of our distribution revenue on the volume of electricity or…

[Operator Instructions]. Our first question or comment comes from the line of Insoo Kim from RBC Capital Markets.

Starting with the sales growth at the gas level, I see that the weather-normal gas growth of 0.5% for the quarter seems a bit softer than what you guys report in prior quarters. What are some items that's accounting for that softness and do you attribute that to more onetime events or is it some more of a secular trend going forward?

Yes. We saw a pretty stronger growth in the residential sector. So year-over-year, even on a weather-normalized basis, the residential growth was pretty robust. What we did see in the first quarter this year is some production declines in a couple of our larger customers on the gas side. And it's difficult to tell whether or not some of that will bounce back or return. Sometimes we do see, depending on their own production schedules, things of holidays and different issues that may come up from quarter-to-quarter we will see variances. At this time, we don't see any major deviation. The trend we've been seeing, a 3% to 5% kind of growth in our overall therm sales, and we think we'll see that through the year.

Yes. Insoo, I think it's instructive to take a look at - by the way, I should have mentioned that if you want to watch the video, we posted that to our website. But what we've seen this year is that actually an acceleration of new economic development activities across all sectors of the economy, whether you're talking about health care, hospitality, particularly strong in residential construction. So I feel very comfortable with the fact that the trends that we've seen over the last number of years will continue on into the future.

Understood. Yes, it seemed like there's some disparity, given the economic improvement side you've guys have seen and that's why I thought maybe it was more of a quote, just a onetime quarterly impact, but I guess [indiscernible]

Yes, it was a pretty wacky winter.

You're right. I'll say. On the electric side, to clarify, did you say that for this quarter, the decoupling for New Hampshire was not in place and in 1Q '17 plus the continued year-over-year decline and you're going to start to realize that in the second quarter going forward?

No, it's effective for the full year. So we now have, in New Hampshire, not decoupling but we have a lock-based revenue mechanism, which is more targeted to measure exactly the efficiency savings that we achieve through our programs and then potentially true-up for that. In Massachusetts, as you know, we are fully decoupled, have been for a few years now. And as a result of that, we're not essentially sensitive to declining sales or changing sales due to energy efficiency.

Right. How much load do you expect to, I guess, be able to recover through this mechanism in terms of like that load percentage?

Well, the overall targets for, yes, for energy efficiency would - I think when we look at it, we would be able to recover about $300,000.

Got it. Got it. And then for the Maine, the expected Maine rate case this June for Northern Utilities, is that going to include any completed portion of the TAB program or inclusion into the rate base?

Yes. We do roll in all past TAB adjustments, all past pure adjustments, anything that we've already put in the ground and put into plant then just becomes part of the rate base, and we go forward from there.

Got it. And then finally, the long term. I just - the investment proposals that you guys have out in Massachusetts. And I think last quarter, you were planning on filing one in New Hampshire as well. What's the latest with those 2?

I'm going to have Tom Meissner comment on that a little bit. He's been very active in both dockets in New Hampshire and Maine so - in New Hampshire and Massachusetts, so he'll pick up on that.

In Massachusetts, we're currently expecting hearings at the third week of May, so about a month away. And we should be getting an order later this year on our gridlock proposals there. We have met with the Attorney General's office. We believe we're generally in agreement on the portfolio projects in our plan, so we're not anticipating any surprises and we expect next year to be the first year of actual investments under that plan. In New Hampshire, there's been an ongoing investigation in a large working group. That group submitted its final report to the commission recently with high-level recommendations. As part of that, there's a recommendation that the utilities filed their grid modernization plans to meet the goals that were defined in that report. We are - the commission right now is requesting comments on the report, and we're expecting an order in New Hampshire sometime later this year as well. That order is likely to direct the utilities to submit grid modernization plans consistent with the recommendations of the report. And if that's the case, we'll likely be submitting our grid mod plan next year in New Hampshire.

Understood. And I think if I remember correctly, in the last quarterly call, you guys did say that you expect overall rate base growth to stay within around that 6% historical level with the gas rates that's higher and electric being more moderate over the next few years. With the investments that are proposed for Massachusetts and the New Hampshire, was that would be additive to that level? Or is that kind of embedded in your expectation?

Yes. I think it's a little of both. I mean, I think we've embedded to a degree some spending if there is opportunity to put in new investments on the electric or the gas side that are well received by the regulators and provide us contemporaneous and quality of cost recovery. I think we're in a good position to be able to expand our spending and put some more into rate base. So conservatively, I think we measured 6% as being a weighted average growth rate. I think it's not unrealistic to think 6% to 8% is probably a range that's possible at all really will be based on what we we're able to get commitment from really the regulators in the various jurisdictions where we are to provide us an ability to get cost recovery and support our investment.

Our next question or comment comes from the line of Shelby Tucker from RBC Capital Markets.

Just a follow-up for that to Insoo's question. The [indiscernible] Yes, I'm trying to. I don't expect to add an incremental, at least they expanded the Algonquin pipeline into New England. I was wondering maybe, Bob, if there are other opportunities of further expansion pipeline into the region and what kind of role could Unitil play on these expansions?

Well obviously, the Kinder Morgan project was cancelled. The Atlantic Bridge Project is still a go although they have some regulatory issues to work their way through. I think it might be interesting for Mark to kind of talk about where we're getting our gas supply because he's very unique in the region, and then we can talk about the potential for future pipeline.

Yes. So we - as you have mentioned, the incremental Algonquin and then the Atlantic Bridge Bob has talked about, we did participate in that and have a present agreement in that of 7,500 dekatherms a day delivery capacity on that. In addition to that, where we have focused a lot of our planning, Shelby, is bringing gas really out of the Ontario area, the Dawn Hub in that area bringing gas somewhat on an odd rule of bringing gas up from the shale region of the U.S. across into Canada and then bringing it across the TransCanadian pipeline network and associated networks across there and then back down into Maine where our service territory begins, and that allows us to bring in well-priced gas, very competitive on Dawn. It's the second most actively traded site in North America. We have about 4 Bcf of storage out in that region as well. So with our storage capacity out there, with the Don Hub and a good pipeline contract root we have, we're able to bring in from 40% to 50% of our pipeline gas from the North, a little different route. So we have been very supportive of some of the pipeline construction up there and the work to be able to bring more capacity in. In terms of New England, New England has got some tough choices to make. And really, there's various proposals of how we're going to bring more gas into the New England region, including expanding the LNG capability. There's Access, New England, which has been pretty much shut down with the regulators for the electric utilities. We're going to support various infrastructure improvements to bring natural gas in. I think our hope is that the region can find a way to come together and find ways to bring more incremental pipeline capacity into the region to serve a growing demand for natural gas. In the meantime, as I described, we're finding where we can get markets, where we can get reliable gas supply. We may be fortunate to be closer to the Canadian border in the northern roots than some. But those down in Connecticut or further may have more difficulty.

Shelby, this is Bob. Our understanding is that the New England ISO is about to issue a report that really kind of ups the ante in terms of their concerns about the lack of additional pipeline capacity into the region. They've been fairly academic about it up until now, but I think they're going to raise the profile to make sure that the public officials in the region understand that this is a necessity. It's not a luxury that region cannot afford to allow all the shale gas to be going someplace else as opposed to taking advantage out in the region. Now how that all shakes out and what proposals could come out of that, we'll just have to wait and see.

And then with gas coming in more over from Canada, is there an opportunity to expand Granite State pipeline?

Well, we use up Granite State pipeline pretty much for our own needs whereas, as you know, we're the primary recipient on that. It's pretty - if you look at the way that pipeline is currently constructed, it's pretty much we bring gas into it and drop it off along the northern system at 30-plus, 35-plus different regulator stations. And so that's how we're operating it. I do think that - and it runs along parallel to the - what they call the joint facilities, the PNGTS and the Maritimes pipeline that comes out of the two different parts of the North and they join together in the Portland area and then come down together. And we do run parallel to that pipeline, so there are some various concepts and proposals to try to bring more gas out of the South to feed into those pipelines. And that could have some ramifications on us, on our ability to move gas back and forth as we do have stations along those as well to take gas. So sure, there's lots of stuff going on. We're looking at it all and trying to figure out the best long-term solution and least cost way to continue to grow and serve our customers.

I'll see you at the AGA.

Yes, okay. We'll see you there.

[Operator Instructions]. I'm showing no additional audio questions at this time. I would like to thank everyone for participating in today's conference. This does conclude the program. You may now disconnect. Everyone, have a wonderful day.