Pinnacle West Capital Corp (PNW) 2015 Q3 法說會逐字稿

Greetings and welcome to the Pinnacle West Capital Corporation 2015 third-quarter earnings conference call.

(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'd like to thank everyone for participating in this conference call and webcast to review our third-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 Investor Relations website along with our earnings release and related information. Note the slides contain reconciliations of certain non-GAAP financial information.

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 third-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 section, 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 web site for the next 30 days. It will also be available by telephone through November 6. I will now turn the call over to Don.

Thank you, Paul. And thank you all for joining us today. Pinnacle West delivered a solid quarter with several financial and operational highlights, keeping us on pace with our guidance for the year and setting us up well for next year. The Board also approved a 5% dividend increase last week, effective with the December dividend payment, continuing this predictable return of capital to our shareholders. Jim will discuss the financial results and guidance.

Our operations team did an excellent job maintaining the fleet and the electrical grid again this summer. The Palo Verde nuclear generation station performed well. Unit 2 entered its planned refueling outage on October 10. This outage marks an important milestone. It represents the completion of FLEX equipment installation at all three units.

FLEX addresses one of the main safety challenges at Fukushima, the loss of cooling capability, and electrical power resulting from a severe event. FLEX, short for diverse and flexible mitigation strategies, is an industry-wide initiative with site-specific applicability. It relies on portable equipment to protect against even the most unlikely scenarios.

The transmission, distribution and customer service teams also performed well. Similar to last year, we had a series of monsoon storms over the last few months. 50,000 customers were without power during the worst storm. The vast majority were back on within 24 hours. Due to the storm damage our crews replaced 485 poles, nearly twice the number from the 2014 storm season.

August was particularly hot this year. We hit our 2015 load peak on Saturday, August 15 after temperatures hit over 114 degrees for three consecutive days. This is the first time in modern era with air conditioning that our peak has been on a Saturday.

One data point worth noting is that when our customers were using the most energy at around 5 PM that day, roof-top solar on our system was producing only 38% of its capacity, supplying 75 megawatts of the 7,031-megawatt load since roof-top solar peaks around noon. However, in stark contrast, utility scale solar was producing 80% of its capacity, supplying 140 megawatts of the load, because most utility scale panels are on trackers that move with the sun. Just a couple of hours later when our system load was still high, roof-top solar production was at zero and the only solar production was coming from Solana, our concentrated solar facility with thermal storage capability.

This scenario is not unique to our peak load day and highlights the importance of the electric grid at all hours of the day. Along with a robust and modern grid, modernizing the rate structure is a necessary priority for which we have been advocating.

Let me provide some perspective on how our recent regulatory filings have evolved. Our priority remains clear. We want to continue the dialogue on rate design with the objective of thoughtfully evaluating these policy issues ahead of the rate case application we plan to file in June of next year.

The grid access charge filing we made on April 2 was designed to take another step in this rate transition by increasing the fixed charge to $3 per KW or about $21 per month per solar customer. In August, the Arizona Corporation Commission voted 3-2 to move forward with an evidentiary hearing on the issue. The exact scope and timing of that process was to be determined at another meeting.

Subsequent to that decision, we saw an unprecedented display of political theatre and character attacks by the roof-top solar lobby aimed at paralyzing the Commission. Given that backdrop, we offered an alternative to the Commission in September to forego the request to increase the grid access charge in exchange for a more narrow hearing on the cost to serve customers with and without solar. In connection with this alternative, we filed a summary of a recently concluded cost of service study on October 8.

This study used a methodology that has been tried, tested and validated in utility proceedings across the country, using actual verifiable data. It concluded that each month, APS incurs $67 to serve solar customers that those customers do not pay. This analysis credits solar customers for the measurable costs that APS avoids when a customer installs roof-top solar, primarily reduced fuel cost.

The Commission discussed how to proceed at the open meeting last week. In the end, they voted to move forward with a single generic docket that will investigate both the cost of service issue raised by APS and the value of solar. The procedural calendar will be determined soon by the Commission staff. Although there has been a lot of noise around this issue, we believe moving forward is critical, and we will continue to work with the Commission and key stakeholders in this proceeding.

In addition to the regulatory proceedings we are also learning about the customer and grid impacts through our solar partner roof-top solar program. Our understanding in this area will better inform our efforts to create a modernized rate structure tailored to our customers' energy needs. We've had a lot of interest and are in the process of signing up customers and installing roof-top systems.

Let me now provide an update on a few other items related to our generation portfolio. Our utility scale program, AZ Sun, had two 10-megawatt projects in the Phoenix metro area come on line in September, bringing the program total to 170 megawatts. We will assess the need for more utility scale solar through our resource planning process. We also retired Cholla Unit 2, one of our coal units, as of October 1, in line with our announcement a year ago as part of a broader environmental plan for the Cholla site.

Let me conclude by saying that we remain focused on delivering on our financial and operational commitments. We have a busy calendar over the next couple of years while the state addresses rate design modernization, and we prepare for our rate case filing. We'll remain steadfast to find solutions that benefit all of our customers.

I'll now turn the call over to Jim.

Thank you, Don. Welcome, everybody. We had a solid third quarter as we benefited from our continued cost management efforts and an improvement in our customer sales. Today, I'll discuss the details of our third-quarter financial results, provide an update on the Arizona economy, and review our financial outlook including introducing 2016 guidance.

Slide 3 summarizes our GAAP net income and ongoing earnings. For the third quarter of 2015, we reported consolidated ongoing earnings of $257 million or $2.30 per share, compared with ongoing earnings of $244 million or $2.20 per share for the third quarter of 2014.

Slide 4 outlines the variances on our quarterly ongoing earnings per share. I'll highlight two primary drivers. Higher gross margin increased earnings by $0.28 per share. I'll cover the drivers of our gross margin variance on the next slide. Going the other way, higher depreciation and amortization expenses decreased earnings by $0.12 per share.

Similar to the first half of this year, the variance included the absence of the 2014 Four Corners cost deferrals and related 2015 amortization of the deferrals and costs associated with the acquisition. D&A expenses were also higher due to additional plant service.

Turning to Slide 5, I'll cover a few of the key components of the net increase of $0.28 in gross margin. Higher usage by APS customers compared to the third quarter a year ago contributed $0.08 per share. Weather normalized retail kilowatt hour sales, after the effects of energy efficiency, customer conservation and distributed generation, increased 2.1% in the third quarter of 2015 versus 2014. Collectively, the adjustment mechanisms continue to add incremental growth to our gross margin, as designed, contributing $0.17 per share, primarily the Four Corners adjustor that went into effect on January 1.

Offsetting Four Corners expenses are included in the other drivers, primarily D&A, which I mentioned earlier. The effects of weather variations increased earnings by $0.04 per share. This year third quarter was warmer or made more favorable than normal, while third quarter of 2014 was milder or less favorable compared to normal conditions.

As Don mentioned, August was particularly hot this year where, for the first time since the advent of air conditioning, we hit our peak on a weekend. 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 our adjustment mechanisms.

Slide 6 presents a look at the Arizona economy and our fundamental growth outlook. Arizona's economy continues to grow, much like it has the past several quarters. Job growth in the third quarter in the Phoenix metro area remained above the national average, as it has for the past 17 quarters.

As seen in the upper panel of slide 6, Metro Phoenix added jobs at a 2.8% year-over-year rate. This job growth is broad-based with the construction, healthcare, tourism, financial activities, business services, and consumer service sectors each adding jobs at a rate above 3%. Growth in consumer spending remains robust and expectations are improving for the housing market.

Our expectation for the metro Phoenix housing permits can be seen in the lower panel on slide 6. The housing market is on track to record its best year since 2007 for both total permits and the single-family sector by itself.

Total permits are up more than 12% this year and, notably, single-family permit activity is up over 40%. Permit activity in the third quarter was the highest we seen since the middle of 2007, and home builders continue to report strong traffic in their sales offices. In summary, Metro Phoenix economy continues to grow steadily and is positioned for stronger growth in the next couple years as a drag from the overbuilt real estate market recedes into the past.

As I had mentioned before, Arizona and Metro Phoenix remain attractive places to live and do business, especially as it is situated relative to the high-cost California market. 2015 is turning out to be better than 2014 in terms of job growth, income growth, consumer spending and new construction. And we expect 2016 to be better than 2015.

Reflecting this steady improvement in economic conditions, APS's retail customer base grew 1.3% compared with the third quarter of last year. We expect that this growth rate will gradually accelerate in response to the economic growth trends I just discussed. Importantly, the long-term fundamentals supporting 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 lower half of the range of $3.75 to $3.90 per share, based on the negative effects of weather through September. Year to date, unfavorable weather through September has impacted earnings by approximately $0.08 per share versus normal conditions.

We adjusted our 2015 customer growth down slightly to 1% to 2% from 1.5% to 2.5%, although our sales outlook is unchanged. We are introducing 2016 ongoing guidance of $3.90 to $4.10 per share, which assumes the normal weather. The adjustment mechanisms, particularly transmission and the LFCR, along with modest sales growth are the key gross margin drivers.

O&M is above trend in 2016. However, non-outage O&M spending remains flat in 2016 compared to 2015 with planned fossil outages representing the increase year over year. This includes major planned outages at Four Corners and Cholla which occur roughly every six years.

Separately, the new lease terms related to the Palo Verde sale leaseback at Unit 2 that take effect on January 1, 2016 offset plant and service impacts, and key depreciation and amortization relatively flat year over year. A complete list of the factors and assumptions underlining our guidance is included in our slides.

Our rate base growth outlook remains 6% to 7% through 2018. We have included our updated rate base slide in the appendix. These estimates include bonus depreciation, which we are assuming will be extended for 2015 and 2016. And we continue to forecast that we will not need additional equity until 2017 at the earliest.

Lastly, as Don discussed, the Board of Directors increased the indicated annual dividend last week by $0.12 per share, or approximately 5% to $2.50 per share effective with the December payment.

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

(Operator Instructions)

Thank you. Our first question comes from the line of Dan Eggers from Credit Suisse.

Hi, good morning, guys. If we can just get into the 2016 guidance a little bit. The first question is, you go back to the 1.5% to 2.5% customer growth number. Given the reduction in inventory in Phoenix, is there enough new stock coming online for next year that you can actually hit that number as you look out and see what's getting built?

We do, Dan. We see, as we've talked about, home permits were up 78% in August in the same month a year ago. We're seeing sales up 32% in condo and townhouses. So, we're seeing a lot of activity in the housing market.

Dan, this is Don. I'd refer you, you can do a search on AZCentral.com the website for the Arizona Republic. Just a story that appeared on the 21st of October, I'll just take a selective quote out of that. But over the past two years, approximately 11,000 building permits for single-family new homes have been issued annually. And he said the expectation is that the number will reach 16,000 by year's end.

Okay, good. And then on the O&M cost side for next year, the costs would be flat excluding the maintenance, is what you said. If we thought about what 2017 looks like, how much of that extra maintenance goes away, just to try and normalize out?

Don't think 2017 will be as big as 2016. And when we look for rate case purposes we will use a average of five years or so. So, that will all get blended out in the rate case.

So, the rate case will reflect that, exactly what the 2017 number is.

Yes. We won't get all of it since it's sort of peak but we will get an average over several years, is typically how they do it.

Okay. And then on the rate base forecast, the inclusion of the bonus depreciation there, I think the 2018 rate base number is down to about $400 million. What do you guys do with the bonus depreciation cash given the fact that you don't need any equity?

Use it to fund CapEx. We'll still be in a net negative cash and we'll have to rely on fixed income securities to fund the CapEx but it does reduce our need.

It will reduce our need for debt financing.

Bonus depreciation to us will be about 70% of that reduction in CapEx. The rest is really moving Ocotillo out to 2019 from 2018.

Okay, I've got it. Thank you, guys.

Our next question comes from the line of Greg Gordon with Evercore.

Thanks, hi, guys. My math shows that -- I think my math shows that on the updated rate base forecast that 390 to 410 basically should more or less reflect the 9.5% to 10% ROE band on parent equity in 2016.

That's correct, Greg.

That's consistent with the way you've thought about it in the past?

Correct.

So, to the extent we wind up at the low end or the high end of that range, thinking about the drivers on page 10, obviously this year we're more towards the lower half because weather was mild. Is it fair to assume the mid point of your gross margin guidance range just assumes normal weather?

Yes, it includes normal weather as well as we have those adjustor mechanisms. Two things. The other thing you'll see from a gross margin perspective, we had the negative transmission adjustor in 2015, we should have a positive TCA next year. So, you get the cumulative effect of that, as well.

I'll step back and ask a higher level, more open-ended question. What are the key two or three factors that would cause you to end up at 410 versus what would cause you to end up at 390 -- IE, high end of the range versus low end -- as you think about managing risk in 2016?

I think the higher end of the guidance will reflect a little higher sales growth than we're currently planning. That would be the big driver.

Okay. And you filed a rate case when? And what's the statutory time limit for a decision?

We'll file June 1 of 2016. Typically there's a 30-day sufficiency. And the last case we did in 10.5. We expect it will probably last a little longer with the rate design in there. It's a statutory 12-month time clock, but that gets moved around as you get days of hearings and so on.

So, the goal would be to have rates in place for the summer of 2017, but that could slip?

Yes. In a perfect world we would have it July 1. With the issues in the case on rate design changes and so on, that would be an optimistic scenario, I think.

But isn't that the reason why you're trying to get a lot of that discussion done now in the context of these proceedings that Don just discussed?

Exactly, Greg.

Okay, thanks, guys. Take care.

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

Thank you, good morning. Don, given that the Commission decided to have these hearings on a generic basis -- and I know you guys pushed for them to be more specific and focus on the cost of service side -- is there a concern that they go through the generic process, and then when the rate case comes you've got to go through this once again but with more specific numbers? So, at the end of the day, how much realistically, do you think this moves the ball forward given the generic nature of this discussion?

I think that it will advance the ball. We'll be dealing with not just generic numbers but our numbers specifically, as will the other participants. Jeff Guldner is sitting here next to me and I think he can probably expand on that thought a little bit.

Sure. Ali, remember, the value of solar docket, which was up there, would obviously be reported on a generic basis. The cost of service study that we did is specific with us. So, one of the things that you'd get in the generic proceedings is still some discussion of how do you apply cost allocation factors, how do you think about the cost of service issues, resolve those and then move forward in a rate case, given the Commissioner's policy options that are on both the cost and the value side. And the more of that we can work through ahead of the rate case the more productive that's going to be when you get into the rate case process.

Okay. And then, secondly, it's good to see the growth in weather normalized sales pick up this quarter at 2.1%. With customer growth at that 1.3% level, was there anything specific to this quarter? Would the weather normalization not have worked perfectly in the sense that your sales growth is actually greater than customer growth this quarter, and normally, as you said, that 50 to 100 basis point differential that you see? So, anything to explain why sales growth was stronger than customer growth this quarter?

I'd say the biggest thing, Ali, is a weight comparison last year in the third quarter. Overall, we have 1% sales growth year to date which would reflect the customer growth we're seeing currently. I think a lot of it, too, we look at the roof-top solar and EE and a lot of it's been confidence, too. And I think you're seeing a little more confident consumer in the Phoenix marketplace.

I see, okay. And then on an LTM basis, based on the way you guys calculate ROE, and I know that's all book value when you talk about your targets, can you tell us what is that ROE that you want over the LTM basis, on your math?

I haven't calculated that, Ali. I'll have to look at that.

Okay. But to be clear, on the 2016 outlook, the range reflects at the low end 9.5%, again, based on the book value calculation?

Yes.

And the high end would be 10%, is that right?

Yes.

Got it. Thank you.

Our next question will come from the line of Michael Weinstein with UBS.

Hi, guys. My question has to do with the guidance for 2015. You reduced the retail customer growth a little bit by about 0.5%. But the sales volume is remaining the same. So, that would indicate that there's been an improvement in terms of energy efficiency effects, less of an energy efficiency effect, that you see in 2015. However, when you go forward to 2016 guidance you have an increase in the customer growth rate but still the same sales rate, so that indicates the opposite. Just wondering what's going on with the energy efficiency, demand side management, et cetera.

Michael, I would caution you to look at any quarter and try to extrapolate anything out of a quarter to quarter. I think we are pleasantly surprised by the sales growth year to date. I don't think we're necessarily extrapolating that into 2016 guidance.

Okay. And also just in terms of the rate case filing, is it true you guys are going to have to file or make purchases of new generating assets before you file the case, is that right?

We have no plans to purchase generation assets other than what we're building at Ocotillo, which is a self-build.

So, there's no potential for anything else or at least as far as you can see now?

No, we have some PPAs and other things rolling off and we'll go out next year for all resources, RFP for some time later probably later this decade, and we'll see what we get at that point. But we're a ways off from new generation at this point.

Okay, thanks a lot.

Our next question comes from the line of Brian Chin with Bank of America Merrill Lynch.

Hi, good morning. With the revised rate base numbers including bonus depreciation, can you quantify out the impact of the bonus depreciation, or give us some sense of how big that is relative to the prior forecast?

Yes, the bonus depreciation we expect to be over the two years about $250 million. And I would just think about that as ratably over those two years.

Okay, excellent. And then with regards to the revised bonus depreciation numbers, can you give us an update on any potential needs for equity? I would assume that it reduces that since you're able to take a bonus depreciation and use that for further deployment of capital, but just revise us on what the equity financing needs are, if any, as we go through the next years?

Yes, certainly, the cash and bonus depreciation would minimize the need, if we need anything. We won't do anything until after we get the outcome in the next rate case.

Okay, great. And then, lastly, just what risk do you think there could be under the more narrowly tailored generic proceeding? Is it possible that any delays or extension of that proceeding could bleed into the timing of when you file the rate case? Is there a risk of the two issues melting together? It's a little bit of a springboard question off an earlier question that Ali asked.

Brian, it's Jeff. I don't think it would affect the timing of the filing of the rate case. One of the issues that came up in the discussion a little while ago was we requested that the Commission push to get that decided in the April time frame so that it was ahead of the case. But the procedural conference is still coming up. If it bleeds over that wouldn't affect the filing. Once you file a case you've got a fairly lengthy litigation process.

Okay, great. Thanks a lot.

Our next question comes from the line of Charles Fishman with Morningstar.

If I could go back to the rate base growth once again, 2018, the $400 million decline in generation and distribution, that was bonus depreciation and the delay of Ocotillo. The $200 million decline in transmission, is that all bonus depreciation or is there a project that's been delayed or cancelled that I've forgotten about?

No, we're constantly on an ongoing basis moving capital from year to year, so nothing substantive in terms of delaying big projects or anything like that.

Okay, thank you. That was it.

Our next question comes from the line of Paul Ridzon with KeyBanc Capital markets.

Just very quickly, you said you had 2.1% sales growth and that is after the impact of efficiency; correct?

Yes, and distributed generation.

What would the gross number have been?

A little over 3%.

Okay, thank you very much.

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

Hi, guys. Sorry to beat a little bit of a dead horse. Just want to make sure I understand this. Can you walk us through from your prior disclosures to today's slide deck the change in total expected rate base over the forecast period and just the two or three biggest drivers of that? There's been a lot of onesies, twosies, and I want to make sure I understand what's going on here.

About 70% of the change, roughly, is the impact of bonus depreciation. And the significant amount of the other is just moving Ocotillo out from an in-service date of 2018 to 2019.

And the total change is $400 million or a greater number?

About $400 million.

Got it, okay. Second, when we think about 2017 O&M, should we assume that it dips back down in that year to something closer to what you've guided to for 2015? Or does it stay at that elevated level that you're going to see next year but that you're expecting to get more recovery of that in rates?

We have really not talked about any aspect of 2017 guidance, Michael.

Is the 2016 increase in O&M viewed more as one-timing or viewed as recurring?

I wouldn't call it one time. We do generation outages every year. We're just faced with significant overall at both Four Corners and Cholla in the same year. I'd say the number is elevated based on what we would call a run rate. But I wouldn't call it one-time in any of them.

Got it. And the case you're going to file in mid 2016, will that use a full-year 2015 test year? And what large, if any, known and measurables would be in there?

We'll try to achieve what we had in the past which is the 2015 test year. And then any plant in service 15, 18 months in is post test year plant. There will be some things that are still under construction that won't be in, like the SCRs for Ocotillo unless it's recovered in some other mechanism.

Meaning, you're expecting to potentially get Ocotillo recovered in this, even though Ocotillo is now not due online until 2019?

No, we would not get Ocotillo in this rate case.

So, this rate case is more about just managing lag and getting the SCRs in?

I think this rate case is also a lot about the rate design issue which is how we align our 70% of fixed cost with only 10% of fixed revenue, and try to get more alignment between costs and revenue.

Got it, okay. Thank you, guys. Much appreciated.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

Good morning. It was a court case in the Arizona Court of Appeals which overturns some of the Arizona Corporate Commissions. It was a case that didn't involve you but in theory they are arguing that the solar access fee being outside of a rate case wouldn't comply with the Court of Appeals ruling, if you follow me. I'm sure you guys are familiar with the case.

Is this a moot point, now that you're withdrawing your request? Or is there any risk if this -- and I know the ACC is probably going to appeal it 00 but if this decision were upheld, is there any risk to you guys with respect to -- what would the impact be to you guys if it was upheld? Let me just ask it that way.

Paul, this is Jeff Guldner. If you're referring to a water company case involving infrastructure adjustor, the Commission has appealed that, so it's a Court of Appeals case. They've sought review with the Arizona Supreme Court. What the case dealt with there was how the Commission makes fair value findings, which is somewhat unique to Arizona regulation, how it makes fair value findings in the context of adjustor mechanisms and things like that.

We get them in rate cases. We do typically fair value findings and provisions in almost everything that we do. So, what I think folks are looking for right now is clarify some of the things that were in the Court of Appeals decision. But think the Supreme Court has not yet decided whether to grant review, and if they do you'll see most of the utilities in the state participating in that litigation.

Okay, right. But what I'm wondering is, if they grant review and if ultimately it's upheld, would there be any impact on what you guys have collected in riders or what have you with this access fee? Let me just ask it this way -- would there be an impact on you guys? When you look at the Arizona Court of Appeals decision, what do you think the impact would be if it were upheld?

Part of it would be on how you'd have to make fair value findings in those proceedings. I think most folks would expect the relief to be prospective. So, it would be in how you'd move forward with a different proceeding in terms of making fair value findings that would support whatever the court ultimately came out with.

We've had fuel adjustors, and one of the things that was mentioned in that decision is that a fuel adjustor, which tracks expenses up and down, fuel adjustors have been common in Arizona for decades. That opinion recognized that that type of an adjustor is fine. And if you get into different styles or different models of adjuster it gets a little more complicated and you've got to figure out how you put the fair value piece in. So, it depends on how the guidance is.

So, you guys would be fine with fuel adjustment. That wouldn't be something that would be impact. Would there be any other potential riders or something that we should think about as being potentially impacted? Or would you basically feel that it wouldn't impact you guys that much? Is that what I'm gathering?

We look at all the riders and we'd look at how the fair value provisions and how we handle fair value in each of those cases and how they are litigated or implemented in rate cases. And then if we have to make adjustments in the next rate case then we would.

Okay. Thank you very much.

We have no further questions at this time. I would now like to turn the floor back over to management for closing comments.

Thank you, Christine. Thanks for joining us today. We apologize for the connection issues we had on the call and we look forward to seeing most of you at EEI here in a couple of weeks. Thank you.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.