Pinnacle West Capital Corporation (PNW) Q1 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the Pinnacle West Capital Corporation 2015 First Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Paul Mountain, Director of Investor Relations. Thank you, sir. You may begin.

Thank you, Christine. I would like to thank everyone for participating in this conference call and webcast to review our first quarter 2015 earnings, recent developments and operating performance. Our speakers today will be our Chairman and CEO, Don Brandt; and our CFO, Jim Hatfield. Jeff Guldner, APS’s Senior Vice President of Public Policy; and Mark Schiavoni, APS’s Chief Operating Officer, are also here with us. First, I need to cover a few details with you. The slides that we will be using are available on our recently redesigned Investor Relations website, along with our earnings release and related information. Note that the slides contain reconciliations of certain non-GAAP financial information. Our website now allows you to sign-up for e-mail alerts so I encourage you to register if you would like to receive automatic updates of our filings and news releases. Today’s comments and our slides contain forward-looking statements based on current expectations, and the company assumes no obligation to update these statements. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. Our first quarter Form 10-Q was filed this morning. Please refer to that document for forward-looking statements, cautionary language, as well as the risk factors and MD&A sections, which identify risks and uncertainties that could cause actual results to differ materially from those contained in our disclosures. A replay of this call will be available shortly on our website for the next 30 days. It will also be available by telephone through May 8. I will now turn the call over to Don.

Thanks Paul and thank you all for joining us today. Despite mild weather, we’re off to another solid start this year. Our operations are running well and preparing for the summer peak. Palo Verde nuclear generating station continues to deliver excellent results, and it’s also preparing for the summer with Unit 3 in a planned refueling outage that began Easter weekend. Before Jim discusses the first quarter results and our updated financial outlook there are few regulatory and strategic developments I’ll update you on. First, rate design continues to be a priority for APS and it is so increasingly across the country. We’ve seen progressive steps in other states, as well as by our peer utilities here in Arizona. Salt River Project’s board approved a broad rate design change in February, while Trico, Sulphur Springs, UniSource, and TEP all filed for net metering related changes earlier this year. The steps each utility is taking varies but appropriately addressing the cost shift and lining the fixed and variable cost discrepancy as a top priority. On April 2, APS asked the Arizona Corporation Commission to increase the grid access charge for future residential solar customer from $0.70 per kilowatt to $3 per kilowatt or approximately $21 per month. We’ve asked the ACC to have this effective August 1. In its 2013 decision, the ACC found that an interim monthly charge of $3 per kilowatt was reasonable to cover the cost to operate and maintain the electric grid but decided to begin with a smaller charge of $0.70 per kilowatt and monitor the issue. APS is simply asking the Commission to implement its 2013 decision. Our proposal would not fully resolve the cost shift, but it’s rather intended to be an interim solution until the issue is more fully addressed in the next rate case or another proceeding. RUCO agrees that this interim solution should be approved to help mitigate some of the cost shift before the issue can be dealt with more fully in a rate case. New solar customers would have the option of selecting an existing rate that includes a demand charge. Other components of the future of rate design would include use of the demand charge on a broader scale and sending better price signals to customers by modifying the time of use rate structures. Since 2013, rooftop solar has seen steady growth. Now over 31,000 customers in our service territory have a rooftop solar system installed. This level of activity reinforces our commitment to modernizing our grid and updating our pricing structures to give customers the platform they need to support the different types of energy and services they want. Our APS Solar Partner Program, where APS will be installing and owning rooftop solar on about 1,500 homes, equal to about 10 megawatts, is now being rolled out. We’ve completed two of the three scheduled RFPs to select the Arizona-based companies that will be installing the systems. And we’ve begun soliciting customers on the first group of feeders we’ve chosen for the program. This innovative program allows us to partner with the Electric Power Research Institute to conduct research on maximizing the efficiency and effectiveness of distributed solar generation and its interaction with the grid. In working with various stakeholder groups for this pilot, including the Arizona Solar Deployment Alliance, which represents Arizona-based solar installers, we’re helping Arizona maintain its solar leadership while ensuring our customers are served well. Our utility scale program, AZ Sun, has two projects under construction in the Phoenix metro area that will bring that program to 170 megawatts. Those projects are expected to be online this summer. In fact, our AZ Sun program has largely contributed to another strong showing by APS in Arizona in the Solar Electric Power Association’s Annual utilities solar rankings that were published this week. APS was ranked in the top five in four categories including cumulative megawatts and annual and cumulative interconnections. The Ocotillo modernization project is an important investment to maintain reliability in the Valley and support the growth in renewable generation. We issued an RFP in late January for the incremental capacity at our Ocotillo peaking facility, equivalent to three of the five new units. Bids were received in March and have been evaluated. The RFP affirmed that APS’s bid at the existing Ocotillo site is the most cost effective. Additionally, our analysis of the project, which was reflected in the bid, determined that it was optimal from a customer impact standpoint to have the project completed in 2019 instead of 2018. And Jim will discuss the financial implications of this change. There are couple of transmission-related items to update you on also. First, we recently completed construction of the, what we call the Hang 2 line, or the Hassayampa-North Gila #2 500 KV transmission line. The project remains on schedule and is expected to be energized in the second quarter this year, after testing and commissioning of both the Hassayampa switch yard and the North Gila substation is complete. In total, the 112-mile-long line into Yuma required construction of 390 steel towers through some extremely difficult terrain. This is a very important project for our company to meet customers’ energy needs in southwestern Arizona. And second, the Delaney Colorado transmission line decision is expected by the California ISO this summer. During the bidding collaboration period, TransCanyon and Southern California Edison submitted a joint proposal to the Cal ISO for this project. That replaces the individual bids both parties submitted in November of last year. The collaboration brings together the experience, expertise and proven track record each organization has in their respective states, TransCanyon in Arizona and Southern California Edison in California. Let me conclude by saying that our focus will continue to be to make decisions and investments that position APS in Arizona for sustainable success in a changing energy world. I’ll now turn the call over to Jim.

Thank you, Don. The topics I will cover today are outlined on Slide 3 and included [Technical Difficulty] quarter financial results, an update on the Arizona economy, and a review of our financial outlook. For the first quarter of 2015 we reported consolidated ongoing earnings of $16.1 million or $0.14 per share, compared with ongoing earnings of $15.8 million or $0.14 per share for the first quarter 2014. Slide 4, outlines the variances in our quarterly ongoing earnings per share. I’ll highlight a few of the more significant drivers. An increase in gross margin improved earnings by $0.07 per share. I’ll cover the drivers of our gross margin variance on the next slide. Higher operations and maintenance expenses decreased earnings by $0.03 per share, largely due to fossil generation plant outages. Higher depreciation and amortization expenses decreased earnings by $0.06 per share. This variance includes the absence of the 2014 Four Corners cost deferrals and related 2015 amortization of the deferrals and costs associated with the acquisition price. G&A expenses were also higher due to additional plant in service. These higher costs were partially offset by the Palo Verde Unit 2 lease extension we announced in July of last year. As included in our guidance, G&A will be higher all year largely due to Four Corners. Lower interest expense net of AFUDC benefited earnings by $0.04 per share. The decrease largely reflects reduced interest charges resulting from refinanced long-term debt at a lower rate. Turning to Slide 5, and the components of the net increase of $0.07 in our gross margin, collectively the revenue adjustors continue to add incremental growth to our gross margin, as designed, including the Four Corners rate change that went to effect on January 1 and contributed $0.06 per share. Offsetting Four Corners expenses are included in the other drivers, primarily D&A which I mentioned earlier. The effect of weather variations increased earnings by $0.04 per share. Although weather on both the 2015 and 2014 first quarters were less favorable than normal, the first quarter 2015 benefited from an unseasonally warm March compared to the same month in 2014. While residential heating degree days, a measure of the effects of weather, were 6% higher than last year’s first quarter, heating degree days were 51% below normal 10-year averages. As a result, weather negatively impacted 2015 first quarter by $0.06 per share compared with the historically normal conditions. Lower usage by APS customers compared with the first quarter a year ago decreased quarterly results by $0.01 per share. Weather normalized retail kilowatt hour sales after the effects of energy efficiency programs, customer conservation and distributed generation, were down 0.8% in the first quarter of 2015 versus 2014. The expiration of a long-term wholesale contract at the end of 2014, which is included in guidance, lowered earnings by $0.02 per share. There will be a similar variance each quarter this year. As a reminder, both the O&M and gross margin variances exclude expenses related to the renewable energy standard, energy efficiency, and similar regulatory programs, all of which are offset by comparable revenue amounts under the adjustment mechanisms. Also the impact of our non-controlling interest for the Palo Verde lease extensions are treated in a similar manner. The drivers I discussed exclude these items as there was no net impact on first-quarter results. Slide 6 presents a look at the Arizona economy and our fundamental growth outlook. Arizona’s economy continues to grow much like it has in the past several quarters. Job growth in Arizona and the Phoenix metro area remain above the national average as they have for the past 15 quarters. As seen on the lower right hand side of Slide 6, Arizona added jobs at 2.6% year-over-year rate in the first quarter, the fastest rate of job growth since Q4 2006. Notably, this job growth has occurred without relying on the construction sector. Business services, healthcare, tourism and consumer services are the sectors with the strongest job growth and highlighted diversity of Arizona’s economy. Additionally, several sources have recently ranked the greater Phoenix area as one of the top places for small business and entrepreneurs. The requirement for small business start-ups is very strong. As I indicated before, we believe that job growth we are seeing reflects the attractiveness of metro phoenix and Arizona as a great place to do business with excellent access to California and other markets but with a much lower cost structure. Of the 15 largest US metropolitan areas, the Phoenix metro area ranked second in population growth in 2014. This healthy population and job growth is providing continued support for an improved real estate market. As seen in the upper right hand side of Slide 6, vacancy rates for commercial space continue to edge down, and activity in these sectors has picked up with 2.8 million square foot of industrial space and 4.3 million square feet of office space under construction in the first quarter of 2015. Residential housing demand in metro Phoenix also continues to increase. As I mentioned on our last call the increase in demand is primarily being met by multifamily development. Housing market permit activity can be seen in the panel at lower left. We expect 2015 to be better than 2014 in terms of job growth, income growth, consumer spending and absorption of residential and commercial vacancies and believe that these trends will translate into higher overall housing activity. The future market share for apartments versus single-family homes remains a question and it’s largely dependent on the degree of strength in existing single-family home market. As you can see in the panel up the upper left, existing home prices have recovered substantially from their recession lows and continue to increase year-over-year. Recovery in prices and rents reflects a continual absorption of vacant homes and apartments in metro Phoenix. On balance we see signs of sustained improvement in our economic environment and continued recovery. We expect each successive year in the near-term will be stronger as we go forward. Reflecting the steady improvement in economy conditions, APS’s customer base grew 1.2% compared with the first quarter of last year. We expect this growth rate will gradually accelerate in response to the economic growth trends I just discussed. Importantly, the long-term fundamentals support future population, job growth, and economic development in Arizona appear to be in place. Finally, I will review our earnings guidance and financial outlook. We continue to expect Pinnacle West’s consolidated ongoing earnings for 2015, will be in the range of $3.75 to $3.95 per share. The rate adjustors and cost management remain important drivers. A complete list of factors and assumptions underlying our guidance is included on Slide 7, which are unchanged from our last confirmation of guidance. Looking ahead to 2015 debt issuance, we plan to refinance a $300 million maturity in the second quarter and raise up to $325 million of additional long-term debt as assumed in our guidance. Overall, liquidity remains very strong. At the end of the first quarter, the Parent Company had no short-term debt outstanding and APS had $45 million of commercial paper outstanding. Included in the appendix to today’s presentation are our updated capital expenditures and rate base slides. Based on our revised projections, the total CapEx for the Ocotillo modernization project is now about $500 million, which reflects a 2019 in-service date and a refined estimate from our previous total of $600 million to $700 million. Our rate base growth outlook is still 6% to 7%. As we continue to refine our forecast, we currently expect the equity component of the capital structure for APS will be approximately 54% at the end of this year. Therefore, we will not need to issue equity to support the capital structure for this rate cycle. We now forecast that we will not need additional equity until 2017 at the earliest. This concludes our prepared remarks. Operator, we will now take questions.

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Thank you. Our first question comes from the line of Daniel Eggers with Credit Suisse. Please proceed with your question.

Hey, good morning, guys.

Good morning, Daniel.

On the equity delay, can you just walk through the math of - maybe help us to make sure I understand where the cash is coming in to let you push that out, and then what effect that may have on the math behind the rate case as far as what your equity issue is going to be?

It will not affect the math on the equity issue - issuance. What we have is really the ability to finance our capital structure within the 54% equity component through the issuance of fixed income securities.

So are you guys going to use a layer of Parent level debt to substitute as equity at the utility or is it just the underlying cash flow?

The underlying cash flow. We currently project that the equity component for rate-making purposes at APS will be 54% at the end of the year, which is consistent with the capital structure in our last case.

And then probably given the likelihood of the ideal stay out in the next case, is there - is 2017 just a place marker for a future rate case or is there some other reason why you can’t issue equity then?

No. But Dan, I’d - good question. I’d emphasize Jim’s qualifier on 2017 at the earliest. Without - no, that’s not a placeholder for rate case at that point in time. And it probably would be, if there was equity in 2017 or beyond, it would be to true-up the cap structure for rate case, which conceivably could be beyond 2017, but maybe a year or two.

Okay, got it. And then on the rate base growth at Ocotillo coming later and less, are there some other things that are filling in capital-wise we should be paying attention to?

Well, we have obviously Four Corners. As we go out into the other years, you have pickup in transmission and distribution spend for the most part.

So, you’re comfortable back-filling for that delay?

Oh, yes.

Yes.

Yes. We see real visibility into our rate base growth.

Okay, very good. And then I guess one last question on kind of the net metering proposal change, the fixed charge element. What does that do to the cost attractiveness of solar if you guys were to go to that $21? I know that some of your peers in the state, the numbers they’ve gone to have effectively shut down solar development. Does that - does yours have a similar impact or lesser so?

Dan, this is Jeff Guldner. We obviously don’t think it will. One of the things to consider with that is, when we went to the $0.70 charge that was static. And there was originally a proposal in the recommended order they were considering at the time that would step that up as installations continued, and we continued to meet the distributed energy carve-out in the RPS. And essentially, if we would have followed that, if that would have been adopted and we would have followed that, we would be at the $3 charge. So the challenge right now is that, when you don’t adjust that charge and you’ve got no upfront incentives, every time there is a cost reduction on the installed cost to solar we are not able to capture that. And so we’re paying too much today for the solar that’s going in our territory.

Okay, got it. Thank you, guys.

Our next question comes from the line of Ali Agha with SunTrust. Please proceed with your question.

Thank you. Good morning.

Good morning.

Jim, just to understand the chronology of events as they take place, you filed this fixed charge increase. I guess staff, by the way, came out against it. But in any case, how do you anticipate the process playing out? You’ve asked for this to be implemented by August. There is the rate design proceeding going on and then there is the rate case that you will file, I believe still next year. So can you just help me understand how all of these things sort of play out from here as you expect them to?

Yes. So, Ali, this is Jeff Guldner. So the grid access charge was an interim step. And so, the filing that we made was fairly limited and it was within the context of the case that was addressed in 2013. And so we stayed within that framework and went up to the level of a grid access charge that was supported in that decision, which was the $3 a lot level, all that is interim. All it does is, when that - revenues are collected under that, they go into a balancing account that reduces the amount of the cost shift, and that basically offsets about four times the cost shift that we are seeing today. That’s different from the structural rate design issues, which is a more long-term issue. So that we expect to be addressed in the rate case, and we expect there to be continued discussions around rate design, as we lead up to the rate case. And you are also seeing now more debate around the region. California has got a proposed decision out. All those are talking about the long-term ways to address the cost shifting issue. But that’s very different from the grid access charge. There is an oral argument that will be heard in our case in June, on June 12, and we’ll get more visibility after that oral argument as to how that case will proceed. Staff is recommending that nothing happen in a - occur in a rate case, but we’ve pointed out that what’s happening is, we’re continuing to see that cost shift and it’s building up in front of that next rate case. And without doing something like this, you are not going to see the cost shift addressed until you come out of the next rate case.

Okay. And so just to be clear, on the rate design proceeding and the timing of your rate case filing, can you just remind us what time frame we’re looking at?

So what we’re looking at right now is, we would be beginning stakeholder outreach here in the summer, working towards filing with a 2015 test year, making the filing in mid-2016.

Okay. And then separately, Jim, I know the first quarter is obviously not the biggest quarter by far for you guys, but when I look at the customer growth of 1.2% and the weather-normalized negative 0.8%, both of those numbers have come down relative to what we were trending at the end of last year, any concern with that as you’re looking forward for the year?

No.

Okay. So, those are still anomalies in your mind.

Well, I think, with more multi-family homes and then the housing, you have a longer lag between sort of permits and actual customers. So, we still believe the pipeline is robust and we’ll hit our numbers.

And last question - now with the later need for equity issuance, when we look at that 6% to 7% CAGR for rate base you’ve laid out for us, what kind of EPS growth rate should we be thinking about that’s supported with that kind of a CAGR?

Well, as you know, we haven’t talked specifically about earnings growth except you would expect it somewhere between rate base growth and dividend growth. So again 6% to 7%, to 5% the total would be your parameters.

Okay. Thank you.

Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.

Hey, guys. This is Mike. I’m a little confused. I’m looking at your fourth quarter slide deck, and I’m looking at today’s slide deck, and I’m just looking at the capital spending levels. The - today’s 2015 estimate is down $30 million or $40 million, 2016 is down almost $200 million, 2017 is up about $30 million or $40 million. How do you - how does - given that’s a net decline in capital spending, how do you maintain rate base growth? I understand you’re going to have growth. How do you maintain the same growth rate, I guess, or a similar growth rate?

Well, 2014 dropped slightly so that’s your starting point, and you have Ocotillo pushed to 2018 and 2019. So all you’ve really done is changed the timing of your cash flows on a year-over-year basis, you end up at the same spot.

Meaning by 2019 you wind up at the same growth rate, but it’s kind of very back-end loaded with Ocotillo. And the front end, the three-year growth rate is a lower growth rate relative to the five year?

Correct.

Okay. I wanted to think about the rate case timing and cycle. When do you expect new rates to go into effect?

Well, we’ve sort of assumed, again, getting a rate case done within that 12-month window that we’ve been able to do, that we were able to accomplish in 2011 and 2012 when we actually did it in 10.5 months.

So you would file mid-2016-ish time frame for mid-2017 rates, or something later than that?

No.

Yes.

That’s sort of our planning assumption at the moment.

Any chance you could stay out?

Well, we’ll certainly look at what we earn and where allowed ROEs are. But I think one key component of 2016 is really addressing the cost shift. And so you’d have to look at the pros and cons and the con would be you are just - you are not addressing the cost shift.

Got it. And then, Don, just a bigger picture question about Arizona and utility regulation. If you had to look at the Commission today and some of the actions today, what do you think is different versus the last three or four years, two or three years in terms of goals, directives, focus areas for this Commission versus the last couple years?

I’m not sure there’s a dramatic difference. I think the Commission today is focused on the current environment and creating a sustainable energy future for Arizona, and working with us and the other utilities in a constructive fashion. Times change and the Commission is adapted to it, and I think they are doing it in a very constructive way.

Got it. Thank you, Don. Much appreciated.

You’re welcome.

Our next question comes from the line of Brian Chin with Merrill Lynch. Please proceed with your question.

Hi, good morning.

Hi, Brian.

Given the Tesla battery announcement last night, does it make sense for APS to propose a storage solution kind of like the successful AZ Sun program? What are some of the considerations around that? How do you think about that?

Brian this is Mark Schiavoni. We do have, as part of the 10-megawatt program we talked about that, we have a component in there of a little over 2 megawatts of storage that we are looking at as part of that. So we are continuing to look at the technologies, so not just solar but also battery storage and other technology that may help the grid perform in the long-term.

Gotcha. Thank you very much.

Our next question comes from the line of Michael Weinstein with UBS. Please proceed with your question.

Hi, guys.

Hello.

I was wondering if you look at the slide on PD residential applications, it’s obvious that quarter-over-quarter it’s a pretty large increase. But sequentially, if you look over that - since July it’s been kind of the similar numbers, and I’m just wondering if that’s sort of you expect it to flatten out for the rest of the year or are we going to see that number continuing to double with every month?

I don’t know that we could actually predict what’s going to happen the rest of the year. I think we don’t - certainly we certainly don’t see any slowdown in residential rooftop in Arizona at this point.

Yes, Mark Schiavoni. I think that our application rate has gone up over time, but it does not necessarily mean complete installation down the road. And that’s what we’re trying to better understand, will those applications actually turn into installations.

All right. And in the multi-family home versus single-family home category in that chart that you have, on page 6, it looks like your prediction is for a big decline in multi-family versus single-family. I’m just wondering what drives that and why do you think that’s going to happen?

Well, if you look at home affordability right now, you have very low interest rates and very high rents. That tells us that homebuilding will begin again, home buying will continue to go up. And I think that would echo what the local homebuilders are also saying. Traffic is up significantly, rebates have stabilized. And so we see that cycle beginning to pick up a bit.

Yes, I’ll add, I believe we talked about it on the second quarter call, last year, in our discussions with home builders, they’re predicting, and they’ve got a pretty good plot, of the customer, the potential home buyers that walked away from homes and foreclosures and bankruptcy. And depending on what kind of financing they’re using, they couldn’t buy a home up until the point that burns off their credit rating. And they’re expecting that bubble to occur in late 2015 and going on into 2016, 2017 - again, depending on whether it’s conventional or FHA financing.

And one final question. Is the - for the net metering fee increase, what percentage of the actual cost shift in your latest calculation is that? In previous filings you talked about maybe a $64 to $74 cost shift per month. I’m just wondering what the latest numbers are.

Yes, I mean that’s essentially what you’re seeing, and so you’re going to continue to see the rate making cost shift be around that $65 to $70 range. And so this is going to mitigate a relatively small proportion of that. But right now, within that framework, that’s the mitigation that we’ve got between now and the next rate case because the additional cost shifting, if you’re going to pick that up is more than likely going to be in the context of a rate design change than a rate case.

Okay. Thank you very much.

Our next question comes from the line of Shar Pourreza with Guggenheim. Please proceed with your question.

Shar.

Shar, your line is live. Perhaps, you got yourself on mute.

Sorry about that, I have been on mute. Good morning. With the current - under the assumption that you get approval of the current fixed charge, which is still obviously materially lower than what your real fixed costs are, is there an opportunity in the upcoming rate case to adjust the decoupler, the partial decoupler to also include distributed generation and loss load?

This is Jeff again. So the partial decoupler in there includes distributed energy right now. So, what we’d be looking at in the next case is how do we adjust that. Our proposal would be to adjust that to pick up more of it, make sure that we’re fully capturing it. Right now it doesn’t pick up the full effect.

Okay. And that’s in addition to the fixed cost that you’re currently requesting.

Right. So, if you change the fixed cost and grid access charge, right now it just credits that account. So it credits the revenues that come under that lost fixed cost recovery mechanism, is what it’s called. If you go out into future rate case, if you do rate design changes that changes the effect of the decoupler. So, if you’re decoupling but you’re recovering more fixed costs, your variable costs are what drives the coupling mechanism, those would be lower.

Got it, that’s helpful. And then on the 10 megawatt distributed generation program you have, can you just remind us what the waiting list is or how much it was oversubscribed?

This is Mark. Right now, we’re in a process of looking and vetting various customers that are going to be potential for this program. If you recall, part of the program was technology and we want to look at it from an operational side, as well. We’ve been going through the selection process on our feeders, which ones we want to address. We’ve been starting to get in contact with customers - a little over 3,000 customers that we’ve reached out to for potential subscription. The last hurdle we have is working through our inverters and getting a UL listed inverter for this system and we expect that in the next month or so. So from an actual subscription, we’re just in initial phases. We have about 3,000 we’re addressing currently.

Got it, got it. And then just on the PV application, I know it’s a little preliminary but do have you the April data?

No, have not seen it yet.

Okay. Thanks so much.

Our next question comes from the lines of Charles Fishman with Morningstar. Please proceed with your question.

Thank you. Don, I was wondering if I could go back to a comment you made as part of your opening comments. When you said - I believe you said - that the ultimate solution of the cost sharing between solar and non-solar customers is some type - is a broader use of a demand charge. And I was just curious what your technical capability is of that. I would assume all your industrial customers have demand meters. What percentage of your commercial customers have demand meters? And I’m assuming very few, if any, of your residential customers have demand meters since I don’t believe you’ve had a smart meter installation program to date. Could you address that?

Yes, I actually, I’ll start with the last first. We’ve had one of the largest smart meter deployments in the nation on a per customer. We have all but a small fraction of our residential customers on smart meters.

Do those have demand - are you able to measure demand with those?

Yes. Metering is not an issue. And I think 99.9% of commercial customers have demand reading meters, also.

So, really, from a technical standpoint, you’re ready to go, it’s just getting the regulators to see the light.

Not the way I’d say it, but the metering will not be an issue.

Charles, we also have over 100,000 customers on really a demand charge now - residential. So, we probably have one of the largest deployment of residential demand in the country.

I believe we’re one of only two utilities in the nation that had a demand rate for residential customers before recent times. I think it’s like 110,000 customers are on that.

What I think your smart meter deployment was so long ago I forgot about it. You were one of the first.

I believe that’s correct.

Okay. Thank you.

Okay, Charles.

Our next question comes from Daniel Eggers with Credit Suisse. Please proceed with your question.

Hey, just circling back on a couple things, I guess first of all., as you think about the discussion process of stakeholders on the next rate case filing, is there going to be anything regulatory design wise that you guys are going to look to test out, if more forward-looking mechanism, more clauses? Is there anything we should be thinking about maybe getting put into the next case?

Dan, this is Jeff. We always look at both what’s happened around the country and what other mechanisms are working. Just remember, in some of the post test year plan adjustments and other things that the Commission staff, RUCO and others here have been very forward-looking with, have been very effective in terms of actually bringing more certainty than in some cases you would get with a future test year where you start looking at predictions. So we’re able to do really well, I think, in catching those mechanisms up to plan at the end of the conclusion of a rate case. But obviously we continue to look at that. And that’s part of these process with stakeholder dialogue, to see what kind of engagement we get from stakeholders on things like that.

Okay. And then, I guess, the other question, Don, what’s going on maybe in the solar market for these other territories where they’ve raise the fixed charges a lot? Is it really shutting down solar, as some of the stories have said, or are people getting a little more creative?

I don’t know much about other’s territories other than what I read in the paper on that here locally. But, right after - shortly after the SRP decision, which shifted from, I’ll say, the conventional metering protocol to more demand based, there was an article in our local paper - and Jim or Paul could shoot you the link to that - about some of the local installers who, I know from my conversations with them, knew long term the current construct was not sustainable. And they came back, and they’re looking at using batteries to install in customers’ homes along with solar, and to be able to shift the solar production from maybe midday, just a few hours, to cover the real peak hours, which is the issue we have. The reality is that solar production’s more towards the midday and diminishes significantly by about 4 o’clock. Our actual peak and the peak in the area - so, it would be the same for a solar project - is typically in the 4:30 to 7:30 timeframe. Mark can probably add a little more to the technical side of that.

Yes, Don stated it correctly. With the solar installations being mostly southward facing to maximize the advantage they have over the current rates and that metering program. That’s why our pilot has been so important, is to look at these 10 megawatts that we’re putting on roofs. We’re using westward facing to better understand our distribution system operations going forward to enable all of the technologies that we may be looking at in the future.

What’s the effect on utilization when they go from west to south, total productivity of the solar panel?

What everybody’s heard about is the duck curve. That duck curve is lessened, and so depending on the size or how much you have in that direction. But you can gain about 20% from a production standpoint if you face it westward versus southward.

But the challenge, then, is that customer, they’re losing 20% of the energy production, which is the credit in that metering. And there’s no price signal given to shift it to later in the day for capacity value.

Okay. Thank you, guys.

Our next question comes from the line of Kevin Fallon with SIR Capital Management. Please proceed with your question.

Hi. I just wanted to go back over the timing of the equity. Is equity off the table for the upcoming rate case and wouldn’t be in play until the following rate case after that? Is that what you’re saying?

What we’re saying is, based on where we believe the rate-making capital structure will be at year end for APS, it’s at approximately 34%, which is consistent with the equity of our last case. Therefore, the premise that we need to issue equity to support this capital structure has changed. Couple of factors; one is moving Ocotillo out changes our cash flows, so we don’t need to issue equity until 2017 at the earliest. And then in that case, it would really not be tied to a rate case as much as it would be tied to a source of capital to maintain our rating.

Assuming you’re going to file in 2016, would 2015 be the test year?

Correct.

Okay. So, for that rate case, at the end of the year you would be equal to what you’ve had in the last rate case in terms of equity ratio, so you wouldn’t need to issue equity to be in compliance with that if that’s the same equity ratio you’re going to seek?

Yes. That’s correct.

Okay. And the other question, just in terms of weather-normalized sales, it’s just been so volatile quarter-to-quarter. Could you give a little bit more color in terms of how things are going?

We think, we’re going to hit our forecast for the year, which is slightly positive sales growth and customer growth around two. We see a pipeline certainly in the multi-family. And believe, based on what we’re seeing in terms of oil prices, and talking to local builders, that there will be a pickup in activity later this year that will be reflected into - and is incorporated in our forecast.

Has the volatility in…

Kevin, I wasn’t worried. I mean, the first quarter is a shoulder quarter. We’re really going to look to second and third quarter and see is there any trends here that we need to adjust to. So, I think its wait and see in terms of the volatility.

Do you think that there’s some anomaly in terms of the weather normalization and the fact that you guys are so third quarter driven in terms of results, that that may give a little bit more volatility than the actual underlying? Is that kind of where you see things?

Yes, I think you always see that in the first and fourth quarters, where any sort of anomaly in weather has such a big impact on what we consider normal, that we tend to look at the second and third quarter for - as more trends than the first and fourth, which is consistent with a lot of our numbers in the first and fourth quarter.

Okay. Thank you very much.

Thank you.

Mr. Mountain, we have no further questions at this time. I’d now like to turn the floor back over to you for closing comments.

Thank you. Thanks for joining us today that concludes our call.