埃克西爾能源 (XEL) 2016 Q2 法說會逐字稿

Good day, everyone, and welcome to the Xcel Energy second-quarter 2016 earnings conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead, sir.

Good morning and welcome to Xcel Energy's 2016 second-quarter earnings release conference call. Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer and Bob Frenzel, Executive Vice President and Chief Financial Officer. In addition we have other members of the Management Team in the room to answer your questions.

This morning we will review our 2016 second-quarter results, reaffirm 2016 earnings guidance range and update you on recent business and regulatory developments. As a reminder, some of the comments during today's conference call may contain forward-looking information. Significant factors that can cause results to differ from those anticipated are described in our earnings release and our filings with the SEC.

I'll now turn the call over to Ben.

Well thank you, Paul, and good morning, everyone. Today we reported GAAP and ongoing earnings of $0.39 per share for the quarter, flat with last year. Our year-to-date earnings are slightly ahead of last year but a bit behind expectations reflecting lower-than-expected sales and some unfavorable weather. However, we have taken action to reduce O&M expenses and as a result we are confident in our ability to deliver ongoing earnings solidly within our 2016 guidance range of $2.12 to $2.27 per share. Bob will provide more detail on our financial results in a few minutes.

While it's been a busy quarter, we've made significant progress in our regulatory initiatives. Let me start out by addressing some of the highlights. We're making progress in the Minnesota rate case and have participated in several mediation sessions. As a result, we have reached a settlement in principal with several of the parties but the terms remain confidential until we reach a final agreement. The settlement is anticipated to address all revenue issues. Any settlement would still have to be reviewed by the ALJ as well as approved by the commission.

We also recently received comments by 15 parties on our Minnesota resource plan. Feedback from the parties was generally supportive for our proposal for early retirement of the two units at our Sherco coal plant, replacement of that generation with natural gas combined cycle unit at Sherco and moving forward with significant wind additions in the next five years. A commission decision is expected later this year.

Now turning to Colorado. Yesterday we filed for the implementation of our advanced grid initiative, which comprises major projects to improve the customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures. The project includes the insulation of advanced meters and the implementation of hardware and software applications to enhance the distribution system. The estimated capital investment for the project is $500 million, which is included in our base capital forecast. We're excited about this project and view it as a template for advancing and enhancing our system to meet the needs of our customers.

In July we also filed a decoupling request with the Colorado Commission. The proposed decoupling mechanism would allow PESCO to adjust annual revenues based on changes in weather normalized use per customer for the residential and small C&I classes. Now this is very similar to the program that was approved in Minnesota. We expect commission decisions for both the advanced grid initiative and the decoupling proposal by mid 2017.

And finally, last week we received testimony in our Rush Creek 600 megawatt wind proposal in Colorado. And in general we had strong support for our project, including the staff. The Colorado staff recommended approval of Rush Creek, subject to certain conditions including a capital cost cap, a shortened depreciation life and changes to the timing of the in-service date to coincide with the Pawnee-Daniels transmission line. The staff also recommended a granting approval of interim cost recovery through the electric commodity adjustment clause, or the ECA, as we had requested for the project.

Finally in support of balance disclosure, I should point out that of the nine parties that filed testimony, one intervener, the Sustainable Power Group, recommended the applications should be denied. We remain on an accelerated schedule and we expect a commission decision in November of this year.

With that, I'll turn the call over to Bob to provide more detail on our financial results and outlook in addition to our regulatory update. Bob?

Thanks, Ben, and good morning, everyone. Today we reported GAAP and ongoing earnings of $0.39 per share for the quarter, comparable to the $0.39 per share earned last year. Most significant drivers in the quarter include the following. Electric margin increased earnings by $0.07 per share and natural gas margin increased earnings by $0.01 per share, largely due to rate increases and higher capital rider revenue in various jurisdictions.

Offsetting the higher margins were increased depreciation expense, which reduced earnings by $0.06 per share, higher interest charges, which reduced earnings by $0.02 per share and increased property taxes, which reduced earnings by $0.01 per share. The higher fixed charges reflect our increased capital investment to add renewables and improve the reliability of the system for the benefit our customers.

Our year-to-date earnings are slightly below plan, largely do to lower than expected sales in mild weather experienced in the first quarter. However, we have taken actions to hold the line on O&M expenses to offset these headwinds. As a result, we're confident in our ability to deliver ongoing earnings solidly within the 2016 guidance range.

When we initiated guidance earlier this year, we were anticipating weather adjusted electric sales growth between 0.5% and 1%. This projection included the impact of leap year. However, despite the fact that we continue to see strong customer additions of approximately 1%, our year-to-date weather adjusted electric sales have actually declined about 0.6%, or 1.1% when adjusted for the extra day of sales from leap year.

Our sales continue to be impacted by lower commodity prices on some of our commercial and industrial customers and declining use per customer in the residential class, driven by conservation efforts and gains in home energy efficiency. And while we had expected some C&I growth in the back half of this year, we believe the commodity and economic backdrops make that unlikely. As a result, we've revised our outlook for full-year retail electric sales to be approximately 0.5% below 2015 results, which is consistent with where we are year to date.

And as you've come to expect from the Company, with lower sales we must prudently manage our operating expenses. We've implemented various cost management efforts to limited expenses that partially offset some of our revenue headwinds. Our year-to-date O&M expenses are lower than last year and we expect O&M to be in line at the conclusion of 2016. And we believe that our recent rate outcomes assume we actively manage our costs. Long term, we continue to mitigate O&M increases through our efforts to improve productivity through capital investment and the use of technology.

On the regulatory front we remain busy and have made excellent progress on various proceedings in our states. Details of these can be found in our earnings release but let me provide some highlights.

Last year we filed a multi-year plan in Minnesota, which reflected a requested rate increase of approximately $300 million over three years. This was based on an ROE of 10% and an equity ratio of 52.5%. Interim rates were implemented in January. As Ben noted, we are working to achieve a definitive settlement with several of the interveners. The finalized settlement agreement would still require commission approval.

In New Mexico we reached a unanimous rate case settlement, which will increase rates by about $23 million. The commission is expected to rule on this settlement this month and rates would be implemented shortly after that decision. We also have a pending rate case in Texas in which we're seeking rate increase of approximately $69 million. We initiated settlement discussions and are hopeful that we will reach an agreement. Absent a settlement agreement, we would expect a commission decision in the first quarter of 2017. As a reminder, final rates are retroactive back to July of 2016.

Finally, we have a pending rate case in Wisconsin. In aggregate, we've requested rate increases of approximately $32 million between electric and natural gas. We expect staff testimony later this month with a commission decision in the fourth quarter and final rates implemented in January of next year.

In summary, we continue to make strong progress on various initiatives. In Colorado we filed our Rush Creek application, our resource plan, a decoupling proposal in our distribution grid modernization program. In Minnesota we're seeking to finalize a settlement in principal in our rate case and are moving towards a constructive outcome in our resource plan. We are on track to deliver ongoing earnings solidly within our 2016 guidance range and we expect to grow earnings at 4% to 6% over the long term.

This concludes our prepared remarks. Operator, we'll now take questions.

(Operator instructions)

We'll go first to Jonathan Arnold at Deutsche Bank.

Good morning, guys. So just as we think about the cadence of the second half, you're obviously a -- you're $0.01 ahead in the first quarter. You're flat in the second quarter. But you need, I think, $0.08 in stage 2 to get into the range and presumably more to get solidly in there. Can you talk about whether you see that coming more in Q3, Q4, or just what the likely drivers are? It sounds like O&M might be a piece of the puzzle here but just how we got there.

Well I think it's going to be pretty balanced through the second half, Jonathan. But to answer your question, we -- as we mentioned in the call, we have top line revenues coming from New Mexico and the Texas cases.

We are seeing some favorable weather for a change. July was a good month. And you recall last year we continued to see unfavorable weather.

And I'm very confident in our ability to manage our revenue streams and our cost initiatives. So you put all that together and that should put us solidly in the middle.

Okay great. Thank you. And then just on the Minnesota settlement, you said several parties. Does that include the DOC -- can you say? And is it -- are we likely to see a three year deal or something different?

Yes, Jonathan, I'd just assume keep all the terms and the parties confidential at this point. We want to get the agreement finalized and quickly presented to the ALJ and then move forward from there. So we'll be able to talk more freely about the terms probably in mid August.

Okay great. That's helpful time timing. Thank you. And then I just want wanted to ask if I may just one thing on the up side -- the base and up side capital forecasts.

I think on the grid -- the Colorado grid filing you made, it says in the release that that's largely in the base capital forecast. But then you still have that 12% of the upside CapEx is in grid modernization. So if the Colorado piece is in the base, can you just speak to what's in the 12%?

Yes. That would be making a similar proposal in Minnesota.

Great. Okay. I was guessing that. But I think that's it. Thank you, guys.

We'll go next to Ali Agha at SunTrust.

Thank you. Good morning. So from your numbers -- you've told us that at the OpCo level the earned ROE LTM was 8.89%. Can you remind us what is the authorized weighted average ROE? In other words, how much of a lag will there be when we look at these numbers?

At the OpCo level?

Yes.

Yes well right now our average ROE is somewhere around that upper 9s, call it 9.8. So that would be about a 100 basis point lag.

Okay. And then also drilling into the changes here, so you've lowered the overall electric sales roughly about 100 basis points from your original. And that's $0.05, $0.06 of headwinds if you will. So did I hear you right that you've identified cause that will offset all of that or should we assume the bulk of that will be offset by the costs? I wasn't clear on that.

Well it's the same -- it's various drivers. Cost is a big piece. The additional revenue from Texas and New Mexico and the fact that we are seeing some weather, favorable weather. Put all that together and that's the offset.

Yes. But I would imagine Texas and New Mexico would be obviously factored into your original guidance. So the weather and the cost would be incremental is the way to think about it.

Right, but if you take a look at the O&M and the changes we've made in those assumptions.

Right. And then just to get a sense, also to clarify, when you said all key revenue requirements would be part of this settlement if it gets finalized, does that -- obviously does that include ROE as well? Just to be clear on that, Ben?

Well, yes. ROE would be embedded in the revenue assumptions. Now what needs to still be worked out, just for full disclosure, is some of the rate design elements -- things that some jurisdictions you call phase 2 but in Minnesota are typically combined into one proceeding.

I see. Okay. Great. Thank you.

We'll go next to Jerimiah Booream with UBS.

Hi. Good morning. I just wanted to touch upon the upside CapEx plan first. Obviously you took out the net gas versus last quarter on the upside plan, which I think was about $300 million -- looks like you replaced it with other. Can you provide any color around what the opportunities are there?

Well I think the big opportunities are the continued opportunities we see in renewables in our backyard. And with the extension of the PTC and ITC, we're actively looking at how we can take advantage of that -- of those tax incentives to do even more for our customers. So more to come on that but it's always worth remembering that we had some of the finest wind resources right in our backyard. And that's from Minnesota all the way down to Texas. So continue to look for those opportunities.

That's what we call again steel for fuel opportunities. And it works so well, just like Rush Creek is working so well in Colorado, because you basically are buying wind at a price point less than you can lock in natural gas reserves. So that's a pretty compelling story for customers and I think investors alike.

Yes. And that leads to my second question. So on the front, light of the IRS guidance that was given, do you have any numbers around the potential opportunity, maybe on a megawatt basis, on maybe what might be rate [baseable] on the wind front? Or just how you might handle that going forward on repowering specifically?

On repowering?

Yes. The repowering opportunity in light of the four year construction guidance from the IRS.

Yes I think most of the focus is going to be on new wind. We certainly are going to be looking at repowering opportunities too. But I think they're a little more one off than the opportunities, just the add the incremental wind to the system.

Okay. Thanks.

Next to Chris Turnure at JPMorgan.

Good morning, Ben and Bob. You talked in your prepared remarks about the Rush Creek staff recommendation being favorable and there being some amendments kind of suggested in there. Was there anything that kind of meaningfully deviated from your expectations and your request? And can you clarify what they said in regards to timing on that?

I wouldn't say anything was -- again, it was supportive. But, as I mentioned, the shortened depreciation life, sinking up more closer to the transmission and service -- if all of those recommendations were adopted by the commission, I do think it would change some of the timing of the project. But that would be it.

Chris, the timing that they've suggested would just delay the project going in to service until from 2018 until late in 2019.

Into late 2019. Okay. And how does this project fit into any potential incremental external equity that would be needed to be raised by you guys?

Chris, it's Bob. We've said since the outset of this project that we would not raise any incremental equity associated with this project.

And then my only other question is on your low to growth forecast going in to the year. It obviously is pretty weak year-to-date and it's a little bit more on the commercial and industrial side. So hopefully the impact is not quite as proportionately bad as it would've been on the residential side. But where did you go wrong in hindsight in your forecasting efforts? What was the main cause of that deviation?

I'll start and I'll ask Bob to dip in where he sees fit. I think we were looking for overall a stronger GDP number. Okay. And then we were also looking for more robust commodity markets. And so when the commodity markets, as you know, have been flat -- steel has been very tough, particularly with some of the currency issues internationally -- so that is impacting the larger C&I customers.

Your early commentary -- the margin associated with that is not nearly the same as it ought to be on the residential side. We do believe, however, there is some trickle down impact that may be impacting the smaller C&I customers. So we still have some load coming on but there's been some projects that, talking to our customers, have not materialized as we originally expected. So does that help?

Yes. That was helpful. Thank you.

Next to Scott [Senchak] at [Canon].

Hi. Thanks. Just a question on some of the upside CapEx. If you start to execute on more of this stuff, how should we think about financing and what kind of metrics you want to be at? Would you need any equity if you hit all this stuff? Just any color on that.

Yes, Scott, it's Bob. Our expectation is if we executed on the upside capital case that we would unlikely need any equity in the program. We do watch our credit metrics closely. We've committed to keeping strong credit ratings at the operating company and the holding company but we wouldn't expect to issue any equity in conjunction with the upside capital program.

Okay. Thanks. And then I guess just -- you talked a little bit about more wind in Minnesota. I'm just wondering how is the market up there? Is it able to handle more wind? Are we at a point where it's easy to add more wind? I know SPP has hit some kind of records on wind lately. So just kind of where are you in that marketplace?

[MIS] has a big footprint. And so I certainly think from a reliability standpoint, from a grid standpoint, you can handle more wind. And there's going to be more wind. And it's pretty economically compelling right now. So I'm not too worried about that.

Scott, in Colorado where we're not apart of an RTO, we have experienced wind as high as I think 65% of our load in any particular time. And we've managed to integrate it very well. And part of that is we've developed some of the most sophisticated wind forecasting software in the business and it's helping us be more efficient with wind. So very little curtailments in our wind portfolio. We're pretty proud of that.

Okay. And so that other bucket that's about 22%, I guess how should we think about -- if that is incremental renewables, is that something that has to be done in a rate case or are these kind of one off things? Or how should we think about timing of that as well?

I'm looking at the -- hang on a second. Are you talking about on the upside cases?

Yes, the upside case.

Well listen, remember that we have riders to cover renewable in our big jurisdictions of Minnesota and Colorado.

Got you. So would that need to -- it would still need to be approved before it was able to go in the rider or how would that work?

Yes, that's correct. You still got to get a certificate of public need.

Got you. But the numbers at this point you guys see pretty compelling. Okay. Thank you very much.

Next to Travis Miller at Morningstar.

Good morning. Thanks. If you look across your rate cases that are in process in any kind of regulatory discussions you've had, what would you say are the one or two things, components, that you're seeing the most push back on? Is it ROE? Is it capital structure? Is it CapEx plans, O&M? What components are you seeing the most push back either from interveners or from regulators?

Well I -- it's not really O&M because we're not asking for a lot of O&M. So it's going to be -- and the capital is usually very much aligned with our stakeholders. So I would say the biggest push back is the fact that we've been in a low interest rate environment for a number of years. And it is pushing downward pressure on ROEs. And that's the challenge. The opportunity we have is I think we increasingly are sharpening our pencils and figuring out how to manage our revenue streams and keep cost consistent with where we see sales growth.

So you put all that together and I think we meet the challenge. And I think we're well positioned to meet the opportunities out there, which is finding steel for fuel opportunities. Finding things that are aligned like our advanced grid initiative with what our stakeholders want and balancing that with a really affordable proposition to our customers. And I think we strike the right balance at the end of the day.

Okay. You answered my other question. So appreciate it.

Next to John Barta at KeyBanc.

Thanks. Good morning. Just to take a step back on Rush Creek, I know it has to be reasonably priced and show economic benefit, but what's the underlying driver behind the increased renewables? Is it meeting RPS or what exactly?

Well it's continued to decarbonize our fleet with affordability in mind. So and in this case, what you're doing with Rush Creek is primarily displacing fossil fuels. And so you're lowering your carbon footprint and you're doing it at a price point that is compelling. That's a pretty winning proposition in my book.

Okay. And then just in the Colorado IRP, do you have the long-term load growth assumption?

In the Colorado IRP?

John, I think we'd have to -- why don't you give me a call and we can get back to you on that.

Okay. Thank you.

Next to Ben Budish at Jefferies.

Hi, guys. I just had a question on the low -- a similar question on the low growth forecast post 2016. Just curious what's built into the 4% to 6% growth and what kind of sensitivity there is around any deviations in the load growth.

Well I think beyond 2016 we're looking at flat to marginal sales growth. Okay. So that's the key question there. And embedded in the 4% to 6% is our ability to meet some of the challenges. We talked a little bit about some of the impact of ROEs that have fallen across the nation, our ability to meet that with prudent cost control. And then capturing the great opportunities, again, that are right in our backyard, the steel for fuel opportunities, the decarbonization at an affordable price point. Those are all the things that I would say that are embedded in those growth assumptions.

Okay. And then just one more question. I think earlier in the call you mentioned O&M was expected to be in line at the end of the year? Did you mean in line with the guidance of 0% to 2% or in line as in flat versus 2015.

Sorry, the latter -- in line versus 2015.

Okay. Thank you.

And that concludes today's question-and-answer session. At this time, I'd like to turn the conference back over to Bob Frenzel, Chief Financial Officer, for any additional or closing remarks.

Thanks, everyone, for your attention and time today. We look forward to seeing you next quarter. If you have any questions please follow up with Paul.

Thanks, everyone. Have a good day.

Thank you. This does conclude today's conference. We do thank you for your participation. You may now disconnect.