Avista Corp (AVA) 2016 Q3 法說會逐字稿

Welcome to the Q3 2016 earnings conference call. My name is Richard and I will be your operator for today's call. (Operator Instructions). Please note that this conference is being recorded. I will now turn the call over to Lauren Pendergraft, Investor Relations Manager. You may begin.

Thank you, Richard. Good morning, everyone, and welcome to Avista's third-quarter 2016 earnings conference call. After having to listen to Jason for the last 10 years I hope you are as excited as I am for my first earnings call. I look forward to working with all of you in the upcoming year.

Our earnings and our third-quarter 10-Q were released premarket this morning and they are both available on our website at AvistaCorp.com. Joining me this morning is our CEO, Scott Morris; CFO, Mark Thies; and the Vice President State and Federal Regulation, Kelly Norwood.

I would like to remind everyone that some of the statements that will be made today are forward-looking statements that involve assumptions, risks and uncertainties which are subject to change. For reference to the various factors which could cause actual results to differ materially from those discussed in today's call, please refer to our 10-K for 2015 and 10-Q for the third quarter of 2016, which are available on our website.

To begin this presentation I would like to recap the financial results presented in today's press release. Our consolidated earnings for the third quarter of 2016 were $0.19 per diluted share compared to $0.21 for the third quarter of 2015. For the year to date consolidated earnings were $1.53 per diluted share for 2016 compared to $1.35 last year.

Now I will turn the discussion over to Scott.

Well, thank you, Lauren and good morning, everyone. I am pleased with our third-quarter performance as our results met our expectations.

Throughout 2016 we have continued to invest in our utility infrastructure to enhance the safety and reliability of our system for our customers and to support both electric and natural gas growth.

Current investments include upgrades and maintenance of generation facilities, transmission and distribution equipment, natural gas pipe and new meter technology, some of which are large multiyear projects that have been in progress. The timely recovery of these costs continues to be essential to earning an adequate return on our investors' and shareholders' return.

In October we reached a settlement agreement with all parties on our Idaho electric general rate case that, if approved, will result in new rates beginning January 1, 2017. I am pleased with the settlement in Idaho which gives us the opportunity to continue to provide the safe, reliable energy our customers expect while earning a fair return for shareholders.

We continue to work through the general rate case process in Washington and we anticipate filing a general rate case in Oregon during the fourth quarter.

In Juneau, AEL&P continued its steady performance during the quarter and is expected to meet its earnings targets for the year. In September AEL&P filed an electric general rate case seeking an interim rate increase which, if approved, could take effect as early as November 23, 2016. A permanent rate increase, if approved, could take effect in December of 2017. AEL&P's last rate increase was in May of 2010.

During the third quarter we committed to make investments of up to $25 million over a five-year period in a private equity fund of strategic utility partners. The fund will invest in emerging technologies and products and services throughout the electric supply chain that will benefit utilities and their customers.

Turning to our activities in Alaska. As you know, last year our Salix subsidiary was named as the preferred respondent to an RFP to provide LNG to the Interior Energy Project in Fairbanks. Recently an agreement was entered into between Salix and the Alaska Industrial Development & Export Authority which concludes Salix's involvement in the project.

We anticipate the opportunity to work on the Interior Energy Project and look forward to exploring other LNG opportunities in North America.

With regards to the possibility of bringing natural gas to Juneau with lower oil prices, our two key issues have been identifying a cost effective way to help with customer conversion costs and securing low-cost project financing. We made good progress on both fronts and are in discussions with certain agencies to identify programs that might apply to this project.

If we can get comfortable with these two issues we intend to file an application with the Regulatory Commission of Alaska for authority to build and operate the gas utility in Juneau. And we will keep you posted on the progress we are making each quarter and we will let you know how it is going in the future.

And with that I'm going to turn it over to Mark.

Thank you, Scott. Good morning, everyone. I just want to -- I always start off -- I try to start off with a little sports analogy. So being a lifelong White Sox fan this is going to be a little tough for me, but go Cubbies tonight. I hope they do it in Cleveland.

For the third quarter Avista Utilities contributed $0.20 per diluted share in both 2016 and 2015. On a year-to-date basis Avista Utilities contributed $1.49 per diluted share, an increase from $1.30 last year. The increase in earnings for the year was due to general rate increases, decoupling and customer growth, partially offset by expected increases in operating expenses and depreciation.

We continue to be committed to updating and maintaining our utility systems, as Scott mentioned. We expect Avista Utilities to spend about $375 million in 2016 and we expect AEL&P's capital expenditures to be about $17 million in 2016.

I will turn on -- we'll move on to liquidity and financing plans. As of September 30 we had $140 million of available liquidity under Avista's committed line of credit. And there were no borrowings or letters of credit outstanding under AEL&P's line of credit.

For the first nine months of 2016 we issued 1.6 million shares of common stock for net proceeds of $66 million under our sales agencies agreement. We have 2.2 million shares remaining to be issued under these agreements.

We also issued 0.3 million shares of common stock for net proceeds about $1 million under our employee plans. For the rest of the year we don't anticipate issuing any common stock other than under our employee plans.

In August of 2016 we entered into a term loan agreement in the amount of $70 million with a maturity of December 30, 2016. We borrowed the entire amount which was used to repay a portion of the $90 million in first mortgage bonds that matured in August.

Also in August we entered into a bond purchase agreement in the private placement market for the issuance and sale of $175 million of Avista Corp. first mortgage bonds in December of 2016. The first mortgage bonds will bear a coupon of 3.54% and mature in December of 2051.

The proceeds of the bonds received in December will be used to pay off the $70 million term loan and pay down the outstanding balance of our committed line of credit. In connection with the bond purchase agreement, we settled interest rate swaps and paid a total of $54 million which we expect to amortize over the life of the project.

Moving on to our guidance, Avista is confirming its 2016 guidance to be in the range of $1.96 to $2.16 per share. We expect Avista Utilities to contribute in the range of $1.91 to $2.05 per diluted share for 2016. Our range for Avista Utilities encompasses expected variability in power supply costs and application of the ERM in Washington to that power supply cost variability.

The midpoint of our guidance range for Avista Utilities assumes no benefit or expense under the ERM. We expect the benefit to be in a benefit position within the $4 million debt band resulting in about $0.02 to $0.03 of earnings per diluted share for 2016.

Our outlook for Avista Utilities assumes, among other variables, normal precipitation and temperatures for the remainder of the year and our guidance range encompasses a return on equity for Avista Utilities of 8.6% to 9.2% from the top to bottom.

For 2016 we expect AEL&P to contribute in the range of $0.09 to $0.13 per diluted share and our outlook for AEL&P assumes, among other variables, normal precipitation and temperatures for the rest of the year.

We expect our other businesses to be between a loss of $0.02 to $0.04 per diluted share, which includes costs associated with exploring strategic opportunity. Our guidance generally includes only normal operating conditions and does not include items -- unusual items such a settlement transactions, impairments or acquisitions or dispositions until the effects are known and certain.

With respect to our 2017 earnings guidance, we expect to complete the process in our Washington general rate case by January of 2017 and will provide our 2017 earnings guidance in our February 2017 earnings call.

I will now turn the call back over to Lauren.

Richard, we would like to now open the call for questions.

(Operator Instructions). Chris Ellinghaus, Williams Capital.

You guys identified some start-up costs on this private equity. Can you attach a number to that?

That was really the $0.02 in the other, that we had $0.02 of negative of loss that was -- really almost all of that was the impact of the cost of getting into that fund.

Okay, great. And when does that capital sort of get deployed and is there a targeted return on that fund?

Yes, we expect to have venture capital returns on that fund and that capital will be deployed -- it is already started with its first investments. We expect them to draw over five years. It is a five-year draw. And as they make -- as the fund makes investments we will draw. They are looking at various investments as we speak and they have already made a couple. So we are part of that.

Okay. Can you give us any more color on Alaska? Either Salix or the gas potential?

In regards to LNG in Juneau, Chris, I would just say that we continue to be pleased with the progress we are making. It has been a challenging project, as you know, because the price of oil. But our teams continue to be very creative and continue to look for opportunities.

And while we don't have anything to announce I am pleased with the progress, so we will keep you posted. But I would say that things are progressing positively.

In regards to Salix, you try opportunities -- this one didn't pan out, but there might be others down the pike. So while it is too bad it didn't work out in Fairbanks, we are hopeful that there will be other projects coming our way.

Did Salix not end up working out on the LNG because of the other participants didn't work out, is that sort of how that transpired?

It is really a number of variables. And primarily again, the decline in oil prices is the biggest impact and we just reached an agreement with [ADA] who is running that project that we would be out of that project.

Is that possible to come back as conditions change?

Anything's possible. We are not planning on it at this point; we are looking for -- as Scott mentioned, we are looking for other opportunities.

Okay. Lastly are you working on a settlement in Washington at all?

This is Kelly. The process is essentially complete in Washington other than briefs are due November 7, which is next week. After that it is really in the Commission's lap to make the decision. They have until January 21 to set new rates if they choose to take that loan. We have asked for a rate change effective January 1.

Okay, great. Thanks for the color, guys.

(Operator Instructions). Brian Russo, Ladenburg Thalmann.

The $4 million positive ERM benefit you expect in 2016, how does that compare to the year-to-date ERM? Just trying to get a sense if we should see something positive in the fourth quarter.

Well, again, it is not -- we are in the $4 million band, so that is a zero to $4 million band. And what I said, Brian, was we expect $0.02 to $0.03. And so, we might see a penny in the fourth quarter compared to where we are in the ERM right now. So I don't -- we are at [$2.7 million], so if it goes anywhere it will be a penny either way.

Got it, that is helpful. And any idea about potential size of investment for the gas utility in Juneau?

Well, again, before -- previously we said the total project was $130 million over 10 years; that is if we build out the whole thing. So what we are looking at now is, as Scott mentioned, does that make sense with the customer?

So we think it would be -- that would be the size of the total project. We may start with something smaller if it makes some sense. But we are evaluating all of our options there.

And it really comes down to can we get the -- like Scott mentioned, can we get the customer conversion costs and can we get the lower cost financing. And we are working with agencies to do that. If we figure that out we will file the papers or the proceedings with RCA, the Commission in Alaska.

Okay, understood. And then just want to learn a little bit more about the private equity five-year investment. The corporate drag that you incurred in the third quarter, that is nonrecurring, it was just kind of a start-up cost for you to invest in that fund, is that the way to look at --?

There are management -- annual management fees associated with that fund. So some of it is annual management, so we will see some. But we also expect to see some results as they make investments and those investments turn into earnings.

So again, that is all part of -- we have always said we expect to have up to $3 million of -- or $0.03 in other for -- looking at strategic opportunities. This is going to be one of those things that is in that place -- in that bucket. So we will be consistent with that; we have just identified it specifically to this fund.

And, Brian, the utilities involved in the fund at this point are Southern, National Grid, Xcel, Ameren, Great Plains, Fortis and us. So we feel we bring a good part of expertise to the fund because of our success with Ecova, Itron, Avista Energy and some of our unregulated subsidiaries have done very well. So we feel confident about our investment and we feel good about where we are at.

Yes, just on that point. I know there was a time where you had quite a meaningful investment in these types of funds and you have laid out some large -- larger market cap utilities involved in this process so that is -- in the fund, so that is good. But what makes the best total investment different than historical investments, some that worked out but others that didn't?

Well, for us -- I mean the big thing here it is going to look at a lot of different investments that impact utility customers and it can try out those investments in the customer bases of the companies that are invested in it.

So you have several million customers over the groups -- customer base that if there is a Company that can work -- we can use our customer bases to work through some of these different technologies. And we think that will be as successful for us. We like -- as Scott mentioned, the innovation is part of our DNA.

So this provides us an opportunity to see all different kinds of technologies out there, but not have to pick the fund -- the exact company that we are going to invest all of our dollars in. It is spread over a number of companies, that is what the benefit of this fund. And the people running it are experts in this and we believe that they bring strong expertise to it.

Yes, makes sense. Okay, thank you very much.

(Operator Instructions). Chris Ellinghaus, Williams Capital.

How did the fourth quarter start off precipitation wise for your basin or your river systems?

Chris, we are loving life if you like rain. We just set a record for the most rain ever in the month of October. We got over six inches, which is significantly higher than anything that is normal for the month of October. So I would say it isn't just a good month, it was a great month from a precip perspective.

Okay, great.

So from an overall hydro perspective it will improve for October and November. We will still probably end the year slightly below normal. But we are off to a great start, like Scott said.

Yes, the longer term forecast still shows a La Nina, which means that colder than wetter normal -- or colder and wetter than normal.

And while you never bank on that kind of stuff because, again, it is not precise; but it is a good -- it is at least a good indicator and we feel good about at least that is the forecast. Whether it develops or not is all another thing. But it is good news from that perspective.

At least it is a swing in the right direction, right?

Yes.

Correct.

As far as the start-up cost for the fund, was that anticipated during the year? I'm trying to think about you have this expectation of normally $3 million of drag for sort of some development effort. Is this incremental to that normal spend or was that already anticipated in your budget for the year?

So we are at $0.04 already, we will probably end up at the high end of that range where we are. But when we first did our budget last year did we have this investment in there? No. I mean we have been looking at a lot of different things.

We looked at it, we did an -- the team did an evaluation, we thought it was a good opportunity for us to invest, so we made the investment. Within the overall expectations of guidance it is included in our expectations of guidance as we look forward.

So, just on that component it stands out because it is other, right, it is $0.02 to $0.04. It is such a small range it is hard to say. If that was in that utility it would be noise and we wouldn't even hardly say anything because you would never see it.

Right.

So it does stand out. Was it anticipated? Not at the beginning of the year but throughout the year, yes. And we still expect to be in our guidance range and we expect to be positive in the ERM.

Okay. One more thing about decoupling in Oregon -- not Oregon -- Idaho. That is just commercial and residential, right?

That is correct.

Was there any kind of material leakage in terms of the decoupling mechanism in the quarter?

No. If you look at the results after the fact it is really accomplishing what we intended it to accomplish, so it is working actually very well.

Okay. Have you sort of analyzed the mechanism in Idaho to sort of determine what percentage of coverage you end up getting in terms of decoupling?

In terms of the customer classes?

Yes, given that it only covers the commercial and residential, what is the slippage per se?

Right. Yes we did the math on that before we designed the mechanism and the proposed mechanism. I don't have the numbers, but it really is capturing that variability that we were targeting driven by whether it is conservation or weather or the economy.

What we found is for our industrials that they are relatively stable in terms of usage and have been for some period of time. And so this really is capturing what we were after. And if you look at the after -- the [back] returns in Idaho, whether it is electric or gas, we are actually doing fairly well there.

And as far as your Idaho service area, do you have much irrigation?

No.

We have some but nothing compared to what Idaho Power has.

Right, that is why I --.

(multiple speakers) irrigation load is in Washington, Chris.

Yes, I just wanted to see because it is a pretty substantial issue for Idaho Power. Okay, thanks a bunch.

Brian Russo.

Just correct me if I am wrong, but the total CapEx for 2016 of $392 million, is that below a prior forecast of $432 million?

No, I don't know where you got that. (multiple speakers) where we originally were $375 million, so --.

Okay, got it. I will have to refresh that. Thank you.

Okay, thanks.

And at this time I see we have no further questions. I would like to turn the call over to Lauren for closing remarks.

I want to thank everyone for joining us today. We certainly appreciate your interest in our Company. Have a great day.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.