Pinnacle West Capital Corp (PNW) 2017 Q1 法說會逐字稿

Greetings, and welcome to the Pinnacle West Capital Corporation 2017 First Quarter Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded. I would now like to turn the conference over to Mr. Ted Geisler, Director of Investor Relations for Pinnacle West. Thank you, Mr. Geisler. You may now begin.

Thank you, Manny. I would like to thank everyone for participating in this conference call and webcast to review our first quarter 2017 earnings, recent developments and operating performance. Our speakers today will be our Chairman and CEO, Don Brandt; our CFO, Jim Hatfield. Jeff Guldner, APS's Senior Vice President of Public Policies, is also here with us.

First, I need to cover a few details with you. The slides we will be using are available on our Investor Relations website along with our earnings release and related information. Note that 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 the 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 the 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 9.

I will now turn the call over to Don.

Thanks, Ted, and thank you all for joining us today. 2017 has started off in line with our expectations, and we remain well positioned for a very solid year. Before Jim discusses the details of our first quarter results, I'll provide a few updates on our recent regulatory and operational developments. I know APS's rate review is top of mind for many of you, and we continue making good progress with this proceeding. On March 1, we announced a settlement, which has broad-based support. In total, 29 intervenors signed the settlement agreement, including the Arizona Corporation Commission staff; the Residential Utility Consumer Office, or RUCO; members of the local and national solar industry and low-income advocates. The settlement provisions contain a number of benefits for our customers, shareholders and the communities we serve. Details of the settlement are outlined in the appendix of our slides today, and I'll review some of the highlights with you now.

Slide 8 shows the settlement's proposed base rate changes, which includes a non-fuel, non-depreciation base rate increase of $87.2 million per year, excluding the transfer of adjust for balances. Additionally, APS will decrease rates by $53.6 million, attributable to reduced fuel and purchase power cost, and increase rates by $61 million due to changes in depreciation schedules. The result is a total base rate increase of $94.6 million or an overall 3.3% bill increase. Other elements that underpin the settlement, including maintaining our allowed return on equity of 10%, our capital structure and base fuel rate, are also listed on the slide. The settlement contains a number of important financial provisions, which reduce regulatory lag and better align rates with the cost of service. In particular, the settlement provides for a cost deferral order for the Ocotillo Modernization Project and a cost deferral order plus rate adjustment for the selective catalytic reduction equipment at Four Corners. Also, the current property tax deferral continues and the power supply adjustor is expanded to include additional production cost. APS proposed changes to the rate options offered to customers, ensuring the price a customer pays more accurately reflects the way that customer uses the electric grid. This one is an important focus of our filing. The settlement includes meaningful changes to modernize rates, including shifting the on-peak period from 12:00 noon to 7:00 p.m. to 3:00 p.m. to 8 p.m. in the afternoon and early evening, which is more aligned with actual peak usage by customers.

Importantly, new distributed generation customers will be required to select a rate option that has time of use rates, including a grid access charge or demand component. APS was among the first utilities in the nation to introduce time of use rates for residential customers back in 1984. Today, more than half of our customers choose the time of use rate for their service. This settlement would create another first by establishing time of use rates as the standard for all new customers after May 1, 2018, except for our smallest customers. The settlement also contains a self-build moratorium through January 1, 2022, with certain exceptions. For example, the moratorium excludes investments in new combustion turbines that will be placed in service after January 1, 2022. Finally, the settlement includes a 3-year stay-out for the next general rate case application. Under this provision, APS may file its next general rate case on or after June 1, 2019. Last week, the ACC's formal hearing on the APS rate review began and is currently underway. Looking ahead, we anticipate the administrative law judge to issue a recommended order followed by a commissioner vote at an upcoming open meeting. We view the proposed settlement agreement as a further sign of Arizona's constructive regulatory environment. We appreciate the opportunity to continue working with the ACC and various stakeholders to find solutions that balance the interest of customers, shareholders and the communities we serve.

Turning to our operations. Palo Verde Nuclear Generating Station had another successful quarter, operating above a 100% capacity factor. A planned refueling outage for Palo Verde Unit 2 began on April 8. Additionally, at the Four Corners Power Plant, our employees are making solid progress on the installation of selective catalytic reduction equipment and construction activity is ramping up at our Ocotillo Modernization Project. This year, we are investing more in our distribution system than ever before. Our focus on modernizing the distribution grid is not a temporary phase, but instead, a shift in how we prioritize investments, with a greater emphasis on our transmission and distribution business. Over the next few years, we expect to invest $1.8 billion in our grid infrastructure, enabling a more secure and resilient grid, which has greater access to the Western energy market. On April 10, we filed our 2017 Integrated Resource Plan, which includes a 15-year forecast of customer electricity demands and the resources needed to serve our customers reliably in the future. An important part of our forecast is the growing requirement for flexible peaking generation over the planning horizon. By 2025, we expect an additional 1.3 gigawatts of quick start combustion-driven capacity will be needed in order to meet our growing summer peak as well as supplement the intermittency created by solar resources.

Moreover, we are witnessing lower average daily prices on the wholesale market, with sharp price spikes and increased volatility during peak periods. This new pricing pattern is a result of excess energy supply during the middle of the day throughout much of the year, largely created by an oversupply of solar energy in California. In order to take advantage of this oversupply and pass the energy savings to our customers, we value investments and flexible resources that can quickly shut down to allow the import of market power and then quickly ramp back up when demand and prices spike again later in the day. We expect these market conditions to exist for the foreseeable future, and we're positioning our generation investments to be more aligned with these market conditions. Ultimately, this will result in a lower cost of service to our customers, improve reliability for the region and new investment opportunities for our company. This also means that our views on the value of baseload and intermediate generation for our customers are evolving, and we will focus our future investments for new generation towards flexible peaking technology, like combustion turbines and eventually, energy storage, which is better optimized for emerging market conditions.

Finally, I'd like to update you on a change on our executive team. When I became CEO in early 2009, the top of my priority list was to recruit one of the finest legal minds in the electricity industry, Dave Falck, to join the company as our General Counsel. Fortunately for us, Dave accepted the offer and has provided Pinnacle West and me with consistently thoughtful counsel ever since. He's a trusted adviser, so it is with mixed feelings that I share Dave's decision to begin to transition into retirement. Dave will become Pinnacle West's Executive Vice President of Law through his retirement in the spring of 2018, and will continue to advise the Board of Directors and me on governance matters and industry's issues. Dave's transition period allows us to continue our commitment to succession planning and talent development on all levels of our company, and I'm pleased to announce that Jeff Guldner has been promoted to Executive Vice President, and will assume the role of General Counsel for Pinnacle West and APS in addition to his current responsibilities of leading our public policy organization. Jeff's a skilled lawyer and a thoughtful and respected leader with a deep understanding of our industry.

In closing, we're delivering on our commitments and continue to be well positioned for a solid year in 2017. We're focused on completing our rate review filing and maintaining operational excellence while positioning Pinnacle West as a sustainable leader through strategic capital investments.

I'll now turn the call over to Jim.

Thank you, Don, and thank you, again, everyone, for joining us on our call. This morning, we reported our financial results for the first quarter of 2017.

As shown on Slide 3 of the materials, for the first quarter of 2017, we earned $0.21 per share compared to $0.04 per share in the first quarter of 2016. Slide 3 also outlines the variances that drove the change in our quarterly ongoing earnings per share. I'll highlight a few of the key drivers. An increase in gross margin added $0.06 per share compared with the first -- prior-year first quarter period, supported by higher LFCR revenues and favorable weather. Lower net sales in the first quarter of 2017 compared to the first quarter of 2016 decreased earnings by $0.04 per share, where positive effects of customer growth were more than offset by energy savings driven by customer behavior, energy efficiency programs and distributed renewable generation and one less day of sales due to the leap year in 2016. Although sales were down in the first quarter, it should be noted that normalized usage per customer in our first and fourth quarters tend to have more variability than usage in the second and third quarters and results in these periods are less indicative of full year results. As an example of this month-to-month variability, we have seen positive weather-normalized sales growth in April, although I will remind you this is only 1 month of data.

Lower operations and maintenance expense contributed $0.11 per share in the first quarter of 2017, primarily due to lower planned outage costs. As you recall, we had large planned outages at the Four Corners Power Plant in both the first and second quarters of 2016 as part of the plant's routine maintenance schedule. As we previously indicated, we expect additional planned outages at Four Corners this year as we prepare for the SCR installations, the timing of which will be largely focused in the second half of 2017. Higher D&A decreased earnings by $0.04 per share in the first quarter due to increased expenses resulting from additional plant in service. And lastly, you will notice a $0.05 benefit to first quarter earnings, driven by a lower effective tax rate in the current year period, primarily due to the adoption of the new stock compensation guidance in 2016. The new guidance requires income tax benefits and deficiencies, resulting from share-based payments to be recognized in the period in which they occur.

Now turning to Arizona's economy, which continues to be an integral part of our investment story. I'll highlight the trends that we are seeing in our local economy, and in particular, the Phoenix Metro area. In 2017, the Metro Phoenix region continues to have job growth above the national average. Through February, employment in Metro Phoenix increased 2.6% compared to 1.6% for the entire U.S. This above-average job growth is driven largely by the financial services sector. This solid job growth continues to have a positive effect on the Metro Phoenix area's commercial and residential real estate markets. As seen on the upward panel of Slide 4, vacancy rates in commercial markets continue to fall and are at levels last seen in 2008 or earlier. Additionally, over 2 million square feet of new office in the retail space is under construction at the end of the quarter. We expect a continuation of business expansion and related job growth in the Phoenix market, which will, in turn, support continued commercial development. Metro Phoenix has also had growth in the residential real estate market.

As you could see on the lower panel of Slide 4, housing construction is expected to continue the upward postrecession trend. In 2017, housing permits are expected to increase by about 7,000 compared to 2016, driven by single-family permits. In fact, permits for new single-family homes in March were at the highest level since August of 2007. Several factors are driving this increase. Maricopa County was the fastest-growing county in the U.S. in 2016. Also, as I mentioned on previous calls, vacant housing in Phoenix is solidly back to prerecession levels. The activity in the market has provided a meaningful support to home prices, which have returned to levels last seen in early 2008. We believe that solid job growth, low mortgage rates and the opening up of credit to the wave of households who suffered from foreclosures during the recession should allow the Metro Phoenix housing market and the economy more generally to continue to expand at this pace over the next couple of years. Reflecting the steady improvement in economic conditions, APS's retail customer base grew 1.4% in the first quarter. We expect that this growth rate will continue to 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'll comment on our liquidity and financing. On March 21, APS issued an additional $250 million of its outstanding 4.35% senior unsecured notes that mature in November 2045. The proceeds were used to refinance commercial paper borrowings and replenish cash temporarily used to fund capital expenditures. We expect to issue up to $600 million of additional long-term debt this year, one transaction at Pinnacle, including financing of the $125 million term loan and one at APS. Overall, our balance sheet and liquidity remains very strong. At the end of the first quarter, Pinnacle and APS had approximately $91 million and $117 million of short term debt outstanding, respectively.

And just a quick thought on guidance. We do not intend to issue earnings guidance for 2017 until after final approval in APS's pending rate review. However, to assist you with your estimates, a list of key drivers that may affect 2017 ongoing earnings is included in the appendix in today's slides. Additionally, if the proposed settlement and the pending rate review is approved by the Arizona Corporation Commission, we would be comfortable with our ability to continue to fund APS's capital expenditure program with no new equity through our planning horizon.

This concludes our prepared remarks. I'll now turn the call back over to the operator for questions.

(Operator Instructions) Our first question is from Greg Gordon of Evercore.

Looking at your sales statistics for the quarter, did the leap day have an impact on the sort of bottom line demand numbers?

Yes. I would say of the 3.3% lower sales, about 1/3 of that was related to leap year.

Okay, great. And then Commissioner Burns at the ACC had recently made a filing with the ALJ in your case, either asking or recommending that several of his peers be recused from voting in that case. Can you tell us what has occurred subsequent to that, if anything?

Greg, this is Jeff. Nothing has occurred at the commission; the hearing's continuing right now and we expect the hearing will probably wrap up today.

Great. So did the ALJ like said that they're going to opine as to whether or not they would rule on that? Or has there been any guidance coming from the ALJ on whether or not that's even going to be considered?

No. She had commented early in the proceeding that any issues with Commissioner Burns were going to be addressed by the commission.

By the commission, okay. And I guess I apologize for not doing my homework, but on April 17, you guys filed your Integrated Resource Plan. If we look in there, will that give us some sense of the quantum of capital spending that you expect to deal with the sort of these issues that Don laid out so clearly on the call in a qualitative fashion? And does it look like it actually would necessitate a sustained spend -- capital spend in the $1 billion to $1.3 billion range that you're currently spending through post '19?

Yes. Greg, this is Jim. The IRP addressed -- beginning in 2021, I think it specifically talked about PPAs, it's really for the summer period, May through September. I think that the flexible generation that we've talked about is, really, has been carved out of the self-build moratorium, and that would be further off in the horizon.

Okay. Last question for me. The -- Commissioner Little, your former chair, had proposed consideration of an increase in the renewable portfolio standard. Is it your expectation that the commission will take up that consideration of that proposal at any point this year?

I think that's on our expectation. Obviously, any increased renewable spend outside of the $15 million a year in '18, '19 [from area 372] is not currently on our forecast. So that would be incremental capital.

And the next question is from Julien Dumoulin-Smith of UBS.

So let's pick up where Greg left off. Let's talk about storages real quickly, if you can. I'd like to understand, in the context of the IRP, the timing of any associated capital ramp-up of the storage program. It looks like you have roughly 400 megawatts in there in the regulatory process and framework that you would otherwise contemplate to put those storage opportunities in theory in rate base.

Julien, it's Jeff. The IRP has just been filed. So obviously, we're working through -- we'll be working through that and there will be -- share more discussion on that as we move forward. We've got some storage that we're doing right now that is with the Solar Partners program. I'd say the focus we got right now is storage that's related to power quality, local reliability issues. And we're making sure that we have a good understanding of that. And so that's kind of what I -- that's what I view right now when the discussion started.

I think our view on storage at the moment, Julien, is more liability-driven. And I think we'll be seeing more capital outlays for storage but we're taking a very measured approach and making sure we're on the right side of that cost curve on storage. But clearly, it's going to have a part in our future from a capital perspective. And I would say, that's not currently in our forecast.

Right. And just to understand this. Is there any -- if, in theory, you were to move forward with it, what kind of regulatory recovery framework would you think about? Or would this be more conventional CapEx? The only reason I mention this just in kind of thinking about when this program would roll out and how that would roll into the timing of any subsequent rate [case]?

Well, I think if we owned it, it would have to be recovered in the regulatory process. There's not currently a framework for an adjustor mechanism. We also have the PSA expanded, where we can put commission approved battery, pass that cost through the PSA and then recover it that way.

Got it. So there's the potential you could use the PSA to the extent which you build something?

Potentially.

Got it. Excellent. And actually just in tandem with that, rooftop. Obviously, there's a good amount of discussion on the IRP on that front. Can you elaborate a little bit? Is there -- how meaningful of an opportunity for you all is that to the extent which you're looking at the prospect?

Well, we agreed to $10 million to $15 million a year. So we're covered [to the rent]. So as currently contemplated, it's not a big capital line, but it is incremental and can recover concurrently, which is from a capital perspective.

And that is, indeed, embedded in your latest update, right, the extension?

Right.

Okay. Lastly, on Navajo. Can you expand upon the potential scenarios contemplated? I suppose to the extent which the plan is, indeed, left open through some kind of federal program or what have you, is there a scenario in which you would actually receive funds to continue operating the plant? Or is this unlikely something in which if it continues operation, there would be some different owner? I know there's a lot of different iterations out there, if you could kind of high-level summarize it, I'd appreciate it.

Julien, this is Jeff. The -- right now, the group that's focused on getting the initial 2-year lease extension which would allow the operation of the plant to continue through 2019. Then the department of interior has a workshop going that's looking at a variety of different scenarios that could include potential new owners for the plant, but that's -- there's been 2 meetings and there's another meeting coming up later this month, so that's pretty early right now.

So it's not off the table that you guys would continue to operate that plant clearly?

We don't operate...

Have an ownership -- sorry.

I don't know that I would say it's off the table. We're not -- we're only a 14% owner in that plant. So we don't want to speak for SRP who's the owner-operator.

The next question is from Ali Agha of SunTrust.

First question. Jim, what effective tax rate should we be assuming for the year and going forward with these tax rate changes you were mentioning?

I think it will be consistent with prior years. That tax benefit in the first quarter, we typically took over the course of a year in our effective tax rate with the change in accounting guidance, we book it now at the time the shares are issued. It required us to do it in the first quarter, which just stands out because the first quarter is such a small quarter.

Okay. So about 34% or so?

Yes.

Okay. And then coming back to the electric sales. This is the third consecutive quarter we've seen a decline here on a weather normalized basis. Any particular explanation for that? Or what may be happening here?

Well, again, in the fourth and first quarter, with small sales, any sort of weather variation or anomalies pop up from year to year. We look for the second and third quarter, and so far, the second quarter is starting off with weather adjusted positive sales. So I would sort of hold on thoughts on sales until we get through the second quarter, where we have more meaningful amount of sales. I'm worried about it as we sit here today for the year.

I see. And then as part of the settlement, one thing, obviously, that also will get updated is the higher equity ratio layer for you guys. So assuming the second month obviously is approved, does that change your thinking of the underlying earnings power of the company now that you're operating with a higher equity ratio? Does that change the growth outlook from your perspective?

No, not at all. I think it'll -- the equity ratio will more normalize as we fund our CapEx program with long term debt.

Okay. So all else being equal, you don't think the higher equity ratio should lead to higher earnings growth as well?

No. It was good in the context of the settlement, obviously, but not driving meaningful growth.

The next question is from Michael Lapides of Goldman Sachs.

A couple of regulatory questions. So in the IRP, it talks about your filing a 2017 RFP for summer season peaking needs 2021 and beyond. How does -- how do the requirements in the rate case settlement fit into whether APS could either be building [CTs] in the 2022 to 2024 time frame? Or whether you could potentially be buying other people's CTs and putting them in the rate base if that's the outcome of an independent review process in RFP?

Michael, there's a self-build moratorium that's in the case that you'd have to step through the process if you're going to propose a bill. So typically, that's going to be more in the view of a back step, but one of the changes to that moratorium would be an acquisition would be different. So that's changed a little bit from the last moratorium.

Meaning you're allowed to do, in the rate case settlement, an acquisition going through the normal process with the PSC and RFP, but it doesn't preclude acquisitions?

Yes. The moratorium that's proposed in the settlement doesn't preclude the acquisitions but it would affect the self-build.

Got it. Okay. Trying to think through, and this may be a Jim question, trying to think through O&M and some of the lumpiness in O&M. So first quarter '16 had the big outages. First quarter '17, you still had some outages, but not nearly the size that you had in first quarter '16. But fourth quarter or late third, early fourth quarter '17 will, once again, have pretty sizable outages. Is that kind of the right way to think about it? And will those outages look more like what you had this quarter or what you had in the first quarter of '16?

More like the first quarter of '16.

So pretty big?

Yes. It's going to be the major outage for Units 4 and 5 prepping for the SCR installations.

Okay. Are the 2016 and '17 outages -- should we think of this as normal run-off course type of stuff that happens kind of every year? Or is this more stuff that's kind of more one-off-ish? And when we think out to 2018 and beyond, we shouldn't be thinking that O&M stays at this pretty elevated level?

No. Our fossil plant outage O&M is pretty lumpy. '16 and '17 are elevated because of the prep for the SCRs. So I think you would see, as you get out to '18, '19, more normalized fossil O&M.

Okay. And is there a year where we can go back in time and look at O&M and say that was more of a normal year?

I'd say, probably '15 would be more normal.

The next question is from Charles Fishman of MorningStar.

The 3-year stay-out, remind me, that was similar to your last settlement, except it went longer, right, just by your choice?

Correct.

Yes. The last one we could have filed June '15. We elected to not file until '16.

But originally, was it 3 years?

Yes.

And then does the stay-out -- didn't it have provisions and does this one that allow you to go back in under certain unusual circumstances? Does this have something like that?

There's always in kind of every settlement I've seen in Arizona, Charles, there's been force majeure type of provisions. I don't recall a case in which they've actually been used.

Okay, that sounds what I was thinking.

The next question is from Paul Patterson of Glenrock Associates.

Most of my questions have been answered, but I wanted to sort of touch base on something I think I heard on the economics of the area. It astonishes me that, if I got it right or let me know if I got it wrong, but the financial services was the big driver on the commercial side, is that correct?

Correct.

And -- pardon my ignorance, but why -- I don't think of financial services being, in Arizona, that much. What -- is there anything in particular?

We define that broadly, but State Farm relocated their Western operations to Tempe and built 5 buildings on Tempe Town Lake and they're beginning now to populate all of these buildings with the people, and so that's a big driver of that growth.

Okay. And then you also just mentioned that like, basically, things look like they were pretty much around 2008. Now obviously things have changed in the economy and what have you. But do you guys -- what do you feel -- obviously, 2008, in some ways, is not so positive in terms of what followed afterwards. Do you have any sense in terms of the real estate market or anything about how things are on the ground there? In other words, I mean, are you seeing the same kind of real estate activity that you actually saw in 2008? Or could you just elaborate a little bit more on that?

Paul, Don Brandt here. Just a couple of factoids here. Metropolitan Phoenix housing permits is -- are at the highest levels they've been since 2007. Maricopa County is the fastest-growing county in the United States in 2016, eclipsing, I believe, the county where Austin, Texas is located. And we've seen not just in the financial services beyond State Farm a lot of back-office operations are here, call centers. But also, in biosciences, there's a really booming industry that brings a lot of jobs and relatively highly paid jobs.

The next question is from Gregg Orrill of Barclays.

Is it possible to give a sensitivity, an EPS sensitivity to 1% weather-normalized sales growth?

It's about $0.08 after tax.

Okay. And with regard to the LFCR under the new settlement, is it more -- does it result in more recovery than under the prior rate plan?

No, it will be recovered differently. It's going to be demand-based versus volumetric. But the robustness of the LFCR did not change.

The next question is from Michael Lapides of Goldman Sachs.

My apologies. A follow-up. The LFCR running $0.03 to $0.04 a quarter, that stays post rate case implementation roughly? I know it's hard to forecast, but just trying to think about if the rate case changes that at all?

No.

Okay. Second, when we think about the rate case settlement, I've kind of gone through it and it's not easiest document to get your arms around. The increase in the D&A rate, the $61 million, that doesn't drop to the bottom line because your D&A is going to go up. And the moving around of the $53.6 million in the fuel and purchased power, well, that will also not talk to the EBITDA or EBIT line because your fuel and purchase power cost should change, right?

Correct.

Okay. The base rate increase of $87.2 million, are there any costs that are not on your income statement today that will be on your income statement when the rates go into effect? Or is this simply trying to catch up some of the regulatory lag with the investments you've made and the increased costs you've seen?

Well, I wouldn't contemplate recovering any costs that will be new. It does defer the SCRs for recovery in '19 and Ocotillo until the next rate case. But other than that, it would just be really reflecting the capital investment into the system that was -- from the last settlement forward.

Got it. And so what ending period cash tier was that using? What's the ending rate base of that?

'15 rate base was -- do you know, Don?

I don't know.

We'll get that to you.[We'll] have that number.

Okay. I just didn't know if that was a known and measurable number from like, say, 3 months ago or 6 months ago, or is that truly an ending 2015 or early 2016 rate base number?

It was 2015 with 12 months of post test [U. S. land]. So it was really reflective through '16. Our ACC rate base at year-end was $6.8 billion for purposes of Arizona and would have add probably another $300 million of rate base over the course of '16.

Okay. And the only reason why I kind of ask about this is an $87 million, this is a pretty decent revenue increase. And on your share count, if you just kind of tax effect that, that would seem like a pretty decent outcome. I'm just trying to make sure I'm not missing anything, whether there are costs that are increasing significantly relative to what you're incurring today and that's all kind of embedded in that base rate case.

Yes. I don't think you're missing anything.

There are no further questions at this time. I would like to turn the conference back over to management for closing remarks.

Thank you all for joining us today. This concludes our call.

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