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California Water Service’s (CWT) CEO Martin Kropelnicki on Q3 2015 Results – Earnings Call Transcript

California Water Service Group (NYSE: CWT ) Q3 2015 Earnings Conference Call October 29, 2015 11:00 ET Executives Thomas Smegal – Vice President and Chief Financial Officer Martin Kropelnicki – President and Chief Executive Officer Analysts Jonathan Reeder – Wells Fargo Spencer Joyce – Hilliard Lyons Operator Good morning, ladies and gentlemen. Welcome to the California Water Service Group Third Quarter 2015 Earnings Results Teleconference. This call is being recorded. I would now like to turn the meeting over to Mr. Thomas Smegal, Vice President and Chief Financial Officer. Please go ahead, sir. Thomas Smegal Thank you, Dana. Welcome everyone to the third quarter earnings call for California Water Service Group. With me today is Martin Kropelnicki, our President and CEO. A replay of today’s proceedings will be available beginning today, October 29, 2015 through December 29, 2015 at 1-888-203-1112 or at 1-719-457-0820 with a replay pass code of 6725942. Before looking at this quarter’s results, we would like to take a few moments to cover forward-looking statements. During the course of the call, the company may make certain forward-looking statements. Because these statements deal with future events, they are subject to various risks and uncertainties, and actual results could differ materially from the company’s current expectations. Because of this, the company strongly advises all current shareholders as well as interested parties to carefully read and understand the company’s disclosures on risks and uncertainties found in our Form 10-K, 10-Q and other reports filed from time to time with the Securities and Exchange Commission. Now let’s look at our quarterly results. I am going to go through the income statement and some financial highlights and then turn it over to Marty for some other comments. For the third quarter, our net income was $25.1 million compared to net income of $33.7 million in the same period last year for a decrease of $8.6 million rather, earnings per share $0.52 on a fully diluted basis for the quarter as compared to earnings per share of $0.70 in the third quarter of ‘14. In the third quarter of ‘14, the company had received the benefit of the August Cal Water rate case decision by the CPUC. As part of that decision, the company had realized $6.8 million of net income related to interim rates that covered the period from January through June of 2014. Also in the third quarter 2014, the company realized a $2.3 million tax benefit. This tax benefit did not recur in 2015. These two items cover the bulk of the change in earnings for the quarter. Revenue accrual, which you will recall, was a drag on earnings in the second quarter rebounded to some extent, as I will discuss in a moment. Before proceeding to revenue and expense changes, I want to point out and highlight two financial items from the quarter. First, the company’s capital construction was $42.5 million for the quarter, bringing the total for the first nine months of 2015 to $118.3 million. Over the last four quarters, which includes the fourth quarter of ‘14, our construction spending has been over $160 million. We now expect capital construction on the high end of our annual estimate for 2015 and that estimate was $125 million to $145 million. Capital spending, as you will recall on our facilities, which are included in regulated revenue requirement, the primary growth driver for the company’s revenue and net income in the long-term. Second thing I would like to point out. The company’s decoupling balance called the net WRAM receivable shrank slightly to $42.5 million at the end of the quarter despite a 19% water sales decline. The account benefited from $23.6 million of drought surcharges on customers who exceeded their water budgets in the quarter. Since the WRAM balance is recovered through future collections from all customers, the drought surcharges on high users are benefiting the majority of customers who are conserving. Now, let me get back to revenue and expense details for the quarter. Our revenue was down, was $183.5 million, down 4% or $7.6 million. Again, this has to do in most part due to the rate case recognition in ‘14. $10.3 million of extra revenue had been recognized in the third quarter of ‘14. We had a $1 million decrease due to rate changes and balancing account entries. We did have $3.9 million increase in our estimate of unbilled accrued revenue. Average bills at the end of September, which include the effective drought surcharges, were higher than the average bills in June. So, we do see a little bit of a rebound in that factor. Our total operating expenses were $151.3 million for the third quarter, that’s up $0.9 million or 0.6%. Production costs were down 9.8%, or $6.5 million and that’s due to the fact that water production was down 19% in the third quarter with the drought conditions that we have. Our production mix didn’t change from the third quarter of 2014, 50% of total water production is purchased water, 47%, ground water, and 3% surface water. Other changes to operation and maintenance expenses, we had employee wages and benefits that were higher by $3 million. Our drought costs, $1.8 million in the quarter, up from $400,000 in the third quarter of 2014. Conservation program costs increased $1 million. Uninsured loss expense increased $1.4 million due to current assessment of ongoing claims. Maintenance costs were up $1.2 million due to more repairs of mains and services in the quarter. This maybe due to our heightened awareness of leaks in our water systems and the interest of our operators in fixing leaks on an expedited basis per the public perception of those leaks during the drought. Depreciation and amortization is $15.3 million for the quarter, an increase of 4.7% or $0.7 million as driven by higher utility plant. Our net other loss of $400,000 was an increase in the loss amount from $200,000 in the third quarter of 2014. And let’s go to year-to-date. So year-to-date, our financial results, net income of $36.5 million, that’s down 19.4% or $8.8 million. The earnings per share, $0.76 on a year-to-date basis, fully diluted, that’s a decrease of 20% or down $0.19 from the first nine months of 2014. On a year-to-date basis, the major factors of the change are tax benefits which occurred in 2014, representing $4.8 million or about $0.10 on an earnings per share basis, which did not recur in 2015; a shortfall in unbilled revenue that’s carrying forward from our second quarter discussion, on net basis, so far during the year, that’s $4.9 million or about $0.06 on a EPS basis, and increased drought costs, which can only be recovered after regulatory review, it’s $2.4 million more this year or about $0.03 on the EPS basis. So, our revenue for the year-to-date $449.9 million for the year, that’s down 2.2% or $10.2 million. Lower water production costs affect that as well as the unbilled revenue accrual amount. Operation and maintenance expense on a year-to-date basis, they were lower by $1.1 million, or 0.3%. Other changes – sorry, production costs were $158.7 million for the year-to-date, down 9% or $15.6 million. Total water production that decreased 17% on a year-to-date basis. Other factors in O&M and A&G and maintenance are wage and benefits expenses increased $10.6 million, primarily due to normal actuarial changes in pension and retiree health costs, which have been higher all year, offset by lower employee medical costs. Our drought expenses, again up $2.4 million more than in 2014. Regulatory expenses are higher by $0.5 million due to rate case filings in California and Hawaii. Maintenance expenses for the year are up $900,000, that’s due to that higher mains and service repairs. And going on to depreciation, $46.0 million for the year, a decrease of 1.7% or $800,000, driven by lower depreciation rates within the 2014 GRC decision, partially offset by higher utility plant. Our net other income is $200,000 for the year, a decrease of 64% or $400,000 from last year. Now, I would like to turn it over to Marty for some comments. Martin Kropelnicki Thanks, Tom. Good morning, everyone. Thank you for joining us today to review the third quarter of 2015. Three areas I want to cover today. One, I want to give some comments and color on the quarter. It’s a rather confusing quarter when you look at the comparables year-over-year and then you factor in the drought and the effects of drought accounting. So I want to take you through the major items and how I kind of dissected the income statement in doing my review. Second, I want to provide a status update on the drought and our progress towards meeting the mandated water reductions that are mandated by the State of California; and then three, provide an update on the 2015 General Rate Case that we filed earlier this year, in July and give you an update on where we are in the progress of getting that well on its way. First, talking about the quarter, as I said it’s a little confusing with a lot of moving parts, including the accounting for drought surcharges, which is the penalty rate or drought tariff rate for people who are exceeding their water budgets. Essentially, with the mandated compliance order or the Governor Brown’s emergency drought declaration, any household or business that goes over their budget is going to pay two time the highest tier rate and what’s called the drought tariff or what we call drought surcharge. That surcharge is not revenue. Those surcharge costs go to offset anything in the WRAM balance. Let’s take a quick look and as noted also in the press release and as Tom said, in the year-over-year comparables and the third quarter of 2014, we received approval to our authorization for our 2012 general rate case. Included in that approval was an authorization for us to collect our interim rates, this is the revenue the company would have received if the general rate case was concluded on-time and new tariffs going into effect on January 1, 2014. That amount was about $10.3 million of revenue or $6.8 million of net income associated with that authorization and the true-up. In addition, as in the press release and as Tom mentioned, we have that one-time tax credit, which is a non-recurring item of $2.3 million. So when you look at the non-recurring items for the quarter, you have about $0.19 associated with the GRC catch-up from the third quarter of last year and the tax credit that was booked in the third quarter of last year as well. So that’s going to throw the comparables on a year-over-year basis off. Now let’s continue on a little bit with the drought. We do have incremental expenses associated with the drought. The commission at the State of California, the public utilities commission, did authorize us to have a drought memorandum account. So a drought memorandum account is a little different than a balancing account. A drought memorandum account basically has us expense any of the incremental costs associated with the drought that were not anticipated in the rate case, so it flows through the income statement. It affects net income, but allows us to recover those costs at a later date, after we apply for recovery at the commission and they go through a prudency review. Clearly, with everything going on with the drought and we have tried to call out those numbers in the press release with the – and especially with the mandated compliance with the state, we have certainly been spending dollars to help our customers hit the required mandatory reductions. And for the third quarter of this year, we had $1.8 million or $0.02 a share of incremental drought expense. Again, these are expenses that were not anticipated in the rate case and directly associated with the drought response. In addition, as Tom mentioned maintenance is up 24%, that’s a lot. But we basically told the crews, any leaks you jump on them. It doesn’t matter what time of day it is. We don’t want to be on the television. We have seen this with some of our brother and sister municipalities, where they will have a main break and it takes them hours and hours to respond to it. So anytime there has been any type of main leak or main break, we have dispatched crews 24 hours a day with the idea of, just fix it don’t waste the water. So that adds another $0.02 of cost. And some of that cost will go to the drought memorandum account. We just have to go through it on a project-by-project basis and determine which were drought related and what was normal maintenance to pick those two apart. So essentially, there is about $0.04 there that we think is attributable to the drought. So you got the $0.19 of non-recurring items, plus the $0.04 of drought related items that will go through the memorandum account. And we did include in the rate case that we filed in July, we did request authorization to collect the drought memorandum account as that rate case gets approved including that into the rate case, which hopefully rates will go into effect January 1, 2017. As Tom mentioned, the company funded CapEx, we are really happy with that. We are starting to see the fruits of our labor going back to 2010 and 2011, when we started to take a more systematic and programmatic view of capital projects and multiyear capital planning. As Tom said, we are well on our way of being in the high end of our range or potentially exceeding our range for the year. And the trailing 12 months of $160 million is a new record for the company and we feel really, really good about that. As we announced last quarter, we do have a new VP of Engineering, Rob Kuta. We are in the process of reorganizing the engineering department, focusing on expedited capital delivery on scope, on schedule and on budget, so overall feeling good on the capital side and rate base growth side. Moving on a little bit to the drought, I think we are taking a little bit of a sigh of relief that we have gotten through the long, hot, dry summer months and we are well into fall in the State of California. As you may recall, part of our drought response was to take what we call the customer first approach. We opened up a call center in Southern California with dedicated drought staff. That runs 12 hours a day, 5 days a week. In addition, we put a number of conservation specialists out in the field in all of our large districts to work with our large commercial and heavy use customers. In total, we have about 38 full-time equivalents that are incremental, that are – have just been hired just to help respond to the drought. And that has a monthly burn rate of about $700,000 in incremental expenses. As we mentioned before, we think we are going to spend between $6 million to $8 million in drought response and based on the current run rate and burn rate of the team, we believe that is true. And we anticipate that these expenses will continue through February of 2016, which is when the Governor’s declaration is set to expire. Further on the drought, when you look at how we have been doing, I am very pleased to say that 16 of our districts have continued to exceed the budgeted mandatory reduction targets. And nine of them are missing that target, but most of them are within 1% or 2% of hitting the overall target. So if you compare our production from 2013 to 2015, our production is down about 29% total. So overall, we are making this thing happen. Water supplies have been – have held steady. So we have been monitoring water supplies on a daily basis and we have continued to be able to meet demand in all of our districts. In addition, we recently did polling that we got the results from on October 14. And we wanted to get the pulse of our customer. Again, this is the first time in the history of the State of California where you have had mandatory water reduction cuts. And those cuts ranged from 8% to as high as 36% in our service areas. And so we did a random poll throughout the state, statistically balloted using a polling firm and we got some interesting polling results. When we asked customers overall are they satisfied on a scale of one to five, one being the worst, five being the best, we received a 4.0. In terms of water quality, on a scale of one to five, we received a 4.1. In terms of service, on a scale of one to five, we received a 4.4. And on communications, on a scale of one to five, we received a 4.0. That’s the overall summary of the polling. Did – it did vary a little bit based on three regions: the southern part of the state, the middle part of the state and the northern part of the state. Not surprising, the Central Valley in the State of California, where we have the tightest water supply, we scored the worst. And in Southern California, where you – we are pretty constrained as well, but it’s very, very densely populated, we scored the best. So overall, I was very, very happy with the polling scores. And I think it shows the dedication of the company to work – in terms of working with the customers to help them achieve their goals. As noted in the press release, we did collect $23.6 million of surcharges from customers. Again, these are customers who are exceeding the required and mandatory water budgets, going over their authorized amounts and they are paying a surcharge. That is not incremental revenue of the company nor does the company keep any of those funds, those funds are directly applied to the WRAM balance. So from a rate design perspective, what does this mean, it means basically that customers that are hitting their requirements, and about 75% of all of our customers are hitting their mandatory reductions are doing a great job. They are not paying a drought surcharge. About 25% of our customers have continued to exceed their water budgets. And they are paying a direct surcharge with an authorized drought tariff of two times our highest rate. All the funds that are collected that drought surcharge are applied to the WRAM accounts and they lower the WRAM balances for all the customers in that service area. So from a rate design perspective and then from a pricing perspective, we are very happy with the rate design and that it is penalizing the people who are using the most water and it’s rewarding the people who are conserving the most water. So we believe the rate design is working. Further, we believe that the polling results show that the majority of our customers understand what our approach was when we took a customer-first approach and trying to work with them hand-in-hand to help them hit their budget requirements for their water budgets. In addition, I think it shows the dedication of the Cal Water staff, all of our district managers, all of our customer service managers, all of our people in the field. It’s been a long summer. It’s been a lot of extra hours, but overall we are making this thing happen. And the company and the staff have just done an outstanding job of getting us to where we are in terms of being in compliance with the governor’s orders. Moving on to the General Rate Case, two weeks ago, we finished all of our site tours in California. So, essentially, our rates team with help from all the different departments in Cal Water visited 23 districts and looking at all the capital requirements, doing site visits, reviewing projects. Overall, the feedback from the team is that we were very well prepared for these discussions with the Division of Ratepayer Advocates, or ORA as they are now known and we are moving into the next phase of the rate case. So, it was filed. We have done the site visits. Now, we are answering all the data requests. And the ORA will prepare their report, which we expect to get in the first quarter of 2016. Once we get that report in the first quarter of 2016, we will prepare our response and then we move into what’s called the public participation hearings. And we anticipate that we will have 18 to 20 of these hearings throughout the state with the administrative law judge, in the local districts that we support, taking comments from our customers about the General Rate Case. And once we get through that, we will be in settlement discussions. Probably, hopefully, if things go to plan, kind of the middle of the second quarter and then hopefully, we will proceed from there. We would like to have the rate case completed on schedule, which would be new rates taken in effect to January 1, 2017. So having said that, as I mentioned, we are glad it’s fall. We are looking forward to going into winter and we are making it happen. So, we are very happy with the results of our conservation efforts and really want to commend our customers and our employees for doing an outstanding job for getting our overall production down almost 30% from 2013. Tom, back to you. Thomas Smegal Thanks, Marty. Now, I would like to finish up with just a couple of highlights from the balance sheet. Our net utility plant grew to $1.66 billion as of September 30. Our work-in-progress balance increased to $149 million. As I mentioned earlier, capital investments were $118.3 million on a year-to-date basis. At the end of the quarter, company had $50.8 million in cash and $136.6 million outstanding on its revolving credit facilities. However, at financing activities, after the end of the quarter, subsequent event, on October 13, Cal Water, the regulated California operating subsidiary, sold $100 million in first mortgage bonds in a private placement. The proceeds are being used to pay down the operating company revolving credit facilities and for other corporate purposes. Cal Water has also agreed to sell an additional $50 million in first mortgage bonds on March 13, 2016 subject to customary closing conditions. So that’s the end of our presentation. Dana, we are now happy to take questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] We will go first to Jonathan Reeder with Wells Fargo. Jonathan Reeder Hey, good morning Marty and Tom. First question, the unbilled revenue impacting Q3 that you guys kind of outlined, would you characterize that as fairly typical for the Q3 impact? Thomas Smegal So, we had a lot of discussion about this last quarter. And what we saw at the end of the last quarter was a substantial dip in the unbilled revenue accounts receivable and that affected second quarter earnings. So, what we are seeing for the third quarter, the accounts receivable balance is approximately normal and that has to do both with the billings and the drought surcharge. So, the drought surcharge is adding to that accrual. And so when you compare it to the low number in the second quarter, we did see a bump upward in it. And so we do have to keep in mind as we go forward, there is going to be some difficulty in estimating or guessing, if you will, what that factor is going to be at the end of the year, at the end of the fourth quarter. Three moving parts. First moving part is we expect we will still see conservation from our customers. We may or may not see a continuation of the current level of drought surcharges. And so we are monitoring that carefully, and that could change by the end of the year. The other is that California is experiencing an El Niño, and the question really is whether it’s a wet El Niño as everyone expects or not. And if it occurs by the time the end of the year rolls around, we could see a drop in sales simply because it’s raining a lot in California in the later part of December. So, we have to watch those things very carefully. That does have the potential to have a year-end impact on us if any of those three factors changes. Jonathan Reeder Okay. So, if it’s really wet, sales, I guess, fall off and then that unbilled… Thomas Smegal That will drop. Jonathan Reeder Yes, it will decrease a lot. Thomas Smegal Yes. Jonathan Reeder Okay. And then, go ahead. Thomas Smegal It’s a little hard to predict that obviously, because we aren’t going to know anything from looking at sales in October and November. It’s really going to be the end of December which affects that calculation. Remember that calculation looks at the last say 20, 21 days of the quarter. It’s really going to be dependent upon what happens during that exact period. Jonathan Reeder Right. But I guess, year-to-date, the only thing that was really unusual was the Q2 drop, which was attributable to the conservation, mandatory conservation, going into effect? Thomas Smegal Right. Jonathan Reeder At this point, okay. And then I think you said there is $0.04 of drought-related items that are going to go through the memorandum account, is that year-to-date so far? Thomas Smegal That’s year-to-date, yes. Martin Kropelnicki Yes, that’s right. Jonathan Reeder Okay. And then the full year expectation is still for about $0.08 or? Martin Kropelnicki Yes, I mean, we have ramped up pretty quick and we have had to add more resources, just depending on how each individual district is doing. We have moved resources around to respond to different needs based on the geographical regions. So, I think we were thinking between $0.06 and $0.08 a share and I think we will probably be on the high side of that about $0.07 to $0.08 a share would be my bet based on the current run rate. Jonathan Reeder Okay. So, then I guess year-to-date EPS, we are at $0.76. Last Q4, I think you earned $0.24. And I don’t think there was any noise in there like the GRC catch-up or the tax benefit from a comparable this year, so assuming you would earn something similar, it puts you right around $1 for the full year. And then had it not been for that Q2 decrease in the unbilled revenues, which I think was about $0.13, I guess it would have put you about $1.13. Is that roughly, I guess, in line with your expectations and the right way to be thinking about 2015 EPS power or should we also add like the $0.08 of the drought expense on top of that? How should we think about that? Thomas Smegal No, I think that’s about right in terms of the components of your analysis. Just keep in mind that the $0.13 in the second quarter, we did bite a little bit of that back here in the third quarter with an upward change in unbilled. So, a little bit of that came back, so you need to factor that in as well. Martin Kropelnicki Yes. And I think just for everyone on the call remember that the unbilled revenue it’s simply the GAAP revenue accrual at the end of the period. And it’s not included in the WRAM. So, it’s unbilled. It’s estimated. And as that – as it becomes billed consumption in the next billing cycle, it goes through the WRAM and it’s trued up or down based on our adopted numbers. Jonathan Reeder Okay. I mean, for a – I mean, is there a way to kind of characterize for a typical year like what the unbilled impact might be looking like? I mean, if I understand correctly, I mean, Q2 – well, go ahead, sorry. Thomas Smegal Yes, sorry, Jonathan. So, in a very typical year, you would see no change from December to the next December in unbilled. When you have a rate change as we did have the rate design change at the end of ‘14, you do tend to see a little bit higher unbilled just because bills are higher, if you think about it way. But generally the bump up in unbilled during the summer goes away by the end of the year. So typically, it’s not a real component of earnings. It should – it’s just a floating item. Unfortunately, for this year, it’s been kind of floating downward due to the fact that people have lower bills because the drought is on and they are using less water. Jonathan Reeder Okay. Yes, I got it. Alright, thank you guys. Martin Kropelnicki Thanks, Jonathan. Operator [Operator Instructions] We will go next to Spencer Joyce with Hilliard Lyons. Spencer Joyce Martin and Tom good morning. Martin Kropelnicki Hi Spencer, good morning. Spencer Joyce Just want to jump back to the tax items here for a moment and I know we saw a nice benefit in Q3 ’14, it gave us a bit of a tough comp this year, but I know pretty consistently over the past few years, we have seen some benefits throughout the year that, while maybe one-time, they seem to be somewhat recurring, can you give us a sense of maybe what the Q4 tax rate might look like or maybe what you are gauging for a full year ‘15 here, it looks like may be trending towards a higher rate than perhaps we have seen over the past few years? Thomas Smegal Spencer, I think you are correct there. Let’s talk a little bit about what’s been happening. Back in 2012, I think it was the first time we started incorporating the analysis of the repairs and maintenance deductions. And that 2012 started to look back at prior years, and there were adjustments from prior years. Those are the kind of what you would call non-recurring blips in this tax benefit. And so right now, we continue to have a repairs deduction, but it’s the current year repair deduction. So we are looking at for 2015, our tax rate being about 38%, whereas if you go back to ‘14, the tax was 34%. And so that is a factor. We are just on an ongoing basis now and maybe we have gotten over the hump of the analysis and reanalysis of what those past repairs and maintenance deductions were. Spencer Joyce Okay. So the potentially 38% here in ‘15 versus before in ‘14, is that strictly due to a differing call it CapEx or repair profile this year or were there still some catch-up items in ‘14 that depressed that level? Thomas Smegal So the ‘14 items were other items. They are pretty complicated and they were related to the rate case. It’s something called the South Georgia method of determining the difference between a regulatory item and a tax item, which I have some understanding of but our technical people have a lot better understanding of. So it was kind of the tax change as a result of the rate case, not really a repairs item. It’s a different item. Spencer Joyce Okay. So this year here in 2015 seems to be a fairly clean year than not any special stuff, but perhaps a decent level of repair activity that might be normal moving forward? Thomas Smegal Yes. One of the things, as we talk about the CapEx, a lot of that CapEx is mains. And a lot of those mains will likely qualify under the repair deduction, but that leads us to the tax rate that we have, the 38% rather than the higher statutory rate. So that’s kind of embedded in getting to that number. So again could it be 37%, 39% at the end of the year or probably not going to vary from 38% at this point. Spencer Joyce Okay, perfect, that’s really helpful. Just finally then, I apologize, I had to hop on a little bit late. The $1.4 million uninsured loss that you all noted in the release, can you give us a little color on that and I assume that we could almost adjust that out of earnings, I mean it’s strictly a one-time kind of unique situation? Thomas Smegal Yes. So the company has a self-insured retention level of about $0.5 million on claims. And so periodically, any utility company is going to have claims against it. Right now, our reserve required us to – we were required to increase our reserve by that amount based on a couple of relatively large claims in the quarter. That’s going to vary up and down. And I think if you go back and look, in the third quarter of ‘14 it was at a very low level. So I don’t want you to adjust it out entirely because I think that there is a normal course there. But what happened was just the difference between the third quarter of ‘14 and third quarter of ‘15 resulted in that big difference. We are always having those things. You hope that you don’t have as many. We have a couple this quarter that we had to reserve for. Martin Kropelnicki Yes. And things will happen in the ordinary course of business. Say we have 600 vehicles in our fleet, so there is – as much as we try to avoid accidents, there is always something that happens. There is always a main break that happens. And that self-insured retention, Tom has to look at that on a monthly and quarterly basis and true that up or down based on the new claims that are coming here. Spencer Joyce Yes, absolutely. Thanks for the color there. And I assume, even now we may be in a period of higher activity, if you will with some of the drought stuff. So that’s very helpful. Alright. Martin Kropelnicki Okay, thanks. Spencer Joyce Thank you. Operator [Operator Instructions] And it appears we have no further questions on the phone at this time. Thomas Smegal Okay. Dana, thank you. And I want to thank all of you for your continued interest in California Water Service Group. We look forward to talking with you again with our year end results. Thanks very much. Martin Kropelnicki Thanks everyone. Bye-bye. Operator Again, that does conclude today’s presentation. We thank you for your participation. Thank you for calling.

Empire District Electric’s (EDE) CEO Brad Beecher on Q3 2015 Results – Earnings Call Transcript

Empire District Electric Co (NYSE: EDE ) Q3 2015 Earnings Conference Call October 30, 2015 13:00 ET Executives Dale Harrington – IR Brad Beecher – President & CEO Laurie Delano – VP, Finance & CFO Analysts Brian Russo – Ladenburg Thalmann Paul Ridzon – KeyBanc Capital Markets Julien Dumoulin-Smith – UBS Operator Welcome to the Empire District Electric Third Quarter 2015 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Dale Harrington. Please, go ahead. Dale Harrington Thank you, Laura. Good afternoon, everyone. Welcome to the Empire District Electric Company’s third quarter 2015 earnings conference call. Our press release announcing third quarter 2015 results was issued yesterday afternoon. The press release and a live webcast of this call, including our accompanying slide presentation are available on our website at www.empireDistrict.com. A replay of the call will be available on our website through January 31, 2016. Joining me today are, Brad Beecher, President and Chief Executive Officer; and Laurie Delano, Vice President, Finance and Chief Financial Officer. In a few moments, Brad and Laurie will be providing an overview of our 2015 third quarter year-to-date and 12-month ended September 30, 2015 results, as well as highlights on other key matters. But before we begin, let me remind you that our discussion today includes forward-looking statements and the use of non-GAAP financial measures. Slide 2 of our accompanying slide deck and the disclosure in our SEC filings present a list of some of the risks and other factors that could cause future results to differ materially from our expectations. I’ll caution that these lists are not exhaustive and the statements made in our discussion today are subject to risks and uncertainties that are difficult to predict. Our SEC filings are available upon request or may be obtained from our website or from the SEC. I would also direct you to our earnings press release for further information on why we believe the presentation of estimated earnings per share impact of individual items and a presentation of gross margin, each of which are non-GAAP presentations, is beneficial for investors in understanding our financial results. With that, I will now turn the call over to our CEO, Brad Beecher. Brad Beecher Thank you, Dale. Good afternoon, everyone. Thank you for joining us. Today, we will discuss our financial results for the third quarter year-to-date and 12-months ended September 30, 2015 periods. We will also provide an update on other recent Company activities. Yesterday, we reported consolidated third quarter 2015 earnings of $25.3 million or $0.58 per share. This compares to the same period in 2014, when earnings were $23.9 million or $0.55 per share. Year-to-date earnings through September 30 are $46.7 million or $1.07 per share, compared to $56 million, or $1.29 per share in the 2014 year-to-date period. For the 12-month period ending September 30, 2015, earnings were $57.8 million or $1.33 per share – $1.32 per share on a diluted basis compared to September 30, 2014 12-month earnings of $71.2 million or $1.65 per share. Laurie will provide more details on our financial results in her discussion. During their meeting yesterday, the Board of Directors declared a quarterly dividend of $0.26 per share payable December 15, 2015 for shareholders of record as of December 1. This represents a 4.4% annual yield at yesterday’s closing price of $23.41 per share. On slide 3 of our presentation, we provided a summary of results for the quarter, year-to-date and 12-month ended periods, as well as highlights during the quarter. We’ll discuss these more throughout the call. On July 26, we put Missouri customer rates into effect to begin recovery of our investment in our Asbury Air Quality Control System project. These rates will add around $17.1 million to our annual base revenues, reflecting a lowering of our fuel base by $1.60 per megawatt hour. With these rates now in place and as we announced in our earnings release yesterday, our full-year weather-normal earnings guidance range of $1.30 to $1.45 per share we provided in February of this year remains unchanged. On our last call, we reported plans for our Missouri rate filing during the fourth quarter of this year. As indicated, we made a filing with the Missouri Public Service Commission on October 16, 2015 requesting an increase in annual electric revenues of approximately $33.4 million or 7.3%. The most significant driver in the case is cost recovery for the Riverton unit 12 combined cycle project. As shown on slide 4, at the end of the quarter, construction at Riverton is 93% complete. Project costs were approximately $150 million excluding AFUDC. The tie-in of new and existing equipment is underway. Preparation for testing and commissioning activities will begin later this year, with scheduled completion in early to mid-2016. The combined cycle project will replace the capacity of retiring coal fire generators at Riverton and ensure our compliance with the Mercury air toxic standards and the cross-state air pollution rule. The Riverton project has an estimated total cost of $165 million to $175 million. Other factors in the filing include, increased transmission expense, administrative and maintenance expense and costs incurred as a result of a mandated solar rebate program. The case also reflects cost savings for customers resulting from revised depreciation rates and lower average interest costs. The filings seeks continuation of the fuel adjustment clause which provides for semi-annual adjustments to customers’ bills, based on the varying costs of fuel and purchase power. We expect new rates to take effect for Missouri customers by September 2016. Keep in mind, as we have previously – discussed previously, with an expected in-service date for Riverton in early to mid-2016 and continued similar customer energy sales, we expect 2016 results to be impacted by some depreciation and property tax lag. Laurie will talk more about the new Missouri reg case in a few moments. On October 26, we filed a request with the Oklahoma Corporation Commission for rate reciprocity using the Missouri proposed tariffs. An administrative rule, providing rate reciprocity to any electric Company who serves less than 10% of its total customers within the state of Oklahoma, took effect in August of this year. As a result, future commission approved increases in Missouri rates will be effective for Empire’s Oklahoma customers, subject to approval of the Oklahoma Corporation Commission. I will now turn the call over to Laurie for a discussion of our financial details. Laurie Delano Thank you, Brad. Good afternoon, everybody. As we review our third quarter 2015 earnings per share results of $0.58 compared to our 2014 results of $0.55, I’ll continue to refer to our webcast presentation slides to talk about various impacts to the quarter. As usual, the slides provide a consolidated non-GAAP estimated basic earnings per share reconciliation for the quarter, year-to-date and 12-month ended periods. Again, this information supplements the earnings per share reconciliation and other information we provided in our press release yesterday. As always, the earnings per share numbers throughout the call are provided on an after tax estimated basis. As Brad mentioned, third quarter results were slightly higher compared to the 2014 quarter and pretty much on target with our 2015 earnings guidance. The new customer rates that became effective July 26 reflecting the costs of our Asbury project added positively to the quarter. However, as we spoke about on our last call, we experienced about a month of regulatory lag on Asbury depreciation, property tax and Riverton 12 maintenance contract costs during the quarter due to the timing of the new rates. When comparing to the 2014 periods, our year-to-date and 12-month ended results continued to be negatively impacted by the depreciation, property tax and maintenance contract lag and the very cold weather during the 2014 heating season. Slide 5 provides a roll-forward of the 2014 third quarter earnings per share of $0.55 to the 2015 quarter results of $0.58 per share. The margin callout box on Slide 5 provides a breakdown of our estimates of the various components that resulted in an increase in electric gross margin of approximately $8.7 million or about $0.13 per share. The implementation of our new Missouri retail customer rates in July drove an increase in margin of about $0.06 per share compared to the 2014 quarter. Again, just as a reminder, our $17.1 million increase in annual base revenues is net of a base fuel decrease of $1.60 per megawatt hour, so the resulting change in margin was negligible. Weather and other volumetric factors drove an estimated increase in margin of about $0.04 per share. On system kilowatt hour sales were up across all of our customer classes during the quarter, increasing in aggregate about 3.3% compared to the 2014 quarter. Warmer weather drove an increase of just over 10% in total cooling degree days compared to the same quarter last year. You may recall that July 2014 was among the coolest Julys in the past 30 years. Cooling degree days were also about 5.3% higher than the 30-year average. Our total sales volume for the quarter was pretty much on target with our guidance. Increased customer counts added about $0.01 per share to margin. Other items including the timing of our fuel deferrals combined to add another estimated $0.02 per share to margin when compared to the third quarter in 2014. Our gas segment retail sales declined slightly quarter over quarter. However, gas segment margin was relatively unchanged. As you can see, on the O&M callout box on slide 5, our overall O&M costs were relatively flat quarter over year. An increase in depreciation and amortization expense of approximately $1.5 million, reflective of the higher levels of planned in-service primarily due to our Asbury project, reduced earnings per share about $0.02. Higher levels of plant in-service and an increase in our effective tax rate also drove an increase in property and other taxes, reducing earnings per share about $0.04. Increases in interest charges and changes in other income and deductions combined with reduced allowance for funds used during construction or AFUDC, decreased earnings in aggregate another $0.04 per share. Our year-to-date earnings are $1.07 per share on net income of $46.7 million. This is a decrease of $0.22 per share over the same period last year, when we earned $1.29 per share. However, again, as Brad mentioned, our year-to-date results are on target with our 2015 earnings guidance. As shown on slide 6, increased customer rates and customer growth were positive drivers of the $0.07 increase in margin. The timing of our fuel deferrals and other fuel recovery components were also positive drivers. However, these positive items were offset by the impacts of weather and other volumetric factors, a January 2015 FERC refund to our four wholesale customers which we have discussed on previous calls and reduced margin from our gas segment. Increased production maintenance expense was the primary driver of an increase in overall O&M expenses that lowered earnings per share approximately $0.07 during the period. This increase is reflective of our Riverton 12 maintenance contract which was effective January 1 and the planned major maintenance outage for our steam turbine at our State Line combined cycle facility. We discussed both of these items on last quarter’s call. Again, we’re seeing increased depreciation and amortization expenses reduce earnings approximately $0.08 per share. Increases in property and other tax expenses, interest charges and changes in other income and deductions combined with a reduced level of AFUDC, again drove earnings down about $0.13 per share. Turning to our 12-month ended results, our net income decreased $13.4 million or $0.32 per share on an undiluted basis when compared to the 2014 12-month ended period. Slide 7 provides a breakdown of the various components that result in this period-over-period decrease in earnings. As you can see on the callout box on slide 7, increased customer rates, customer growth and the timing of our fuel deferrals and other fuel recovery components contributed positively to margin. However, these positive impacts were largely offset by weather and other volumetric impacts, the FERC wholesale refund and reduced gas segment margin. These changes netted together increased margin an estimated $0.04 per share year-over-year. The callout box on slide 7 provides a breakdown of consolidated operating and maintenance expenses that drove a $9.3 million or $0.13 year-over-year decrease in earnings per share. As we saw in the year-to-date period, increased production maintenance expense was a significant driver of the increase in overall O&M expenses. Again, as a result of our Asbury project, we’re seeing increased electric depreciation and amortization expense reducing earnings per share around $0.09. Increases in property and other tax expenses reduced earnings another $0.05 per share. Again, increased interest charges, changes in other income and deductions, the dilutive effect of common stock issuances and reduced AFUDC levels, drove earnings about $0.09 per share lower. On slide 8, we’re again illustrating the major drivers of our earnings through 2015 and into 2016. As we have previously disclosed, our guidance range assumed an August 1, 2015 effective date for the new Missouri customer rates. We’ve talked about the depreciation and maintenance expense lag effects on previous calls and today. With the July 26 effective date of our new customer rates, that impact will lessen throughout the remainder of the year. We will, however, continue to see increased maintenance expense as a result of our Riverton maintenance contract. As Brad mentioned, we expect the rates for our newly filed Missouri rate case to be effective in September of 2016. Turning to our balance sheet for just a moment. At September 30, I’m pleased to report our retained earnings balance was $102.9 million. This marks a milestone and that is the first time in Empire’s history, we have reported a retained earnings balance of over $100 million. As I alluded to on our last call on August 20, we received the proceeds from a $60 million delayed settlement offering of privately placed first mortgage bonds. These are 3.59% series bonds and they are due in 2030. We will use the proceeds to refinance some short-term debt and for general corporate purposes. Subsequently at the end of the quarter, we had $16.3 million of short-term debt outstanding out of our $200 million in capacity. Looking forward, we have $25 million of first mortgage bonds that mature in late 2016. At this time, we’re not planning to refinance this debt when it matures. On slide 9, we have updated our trailing 12-month return on equity charge. At the end of the third quarter, our ROE was approximately 7.2%, similar to our second quarter results. Slide 10 represents an updated capital expenditures and net plant projection plan for the next five years. As you can see on the slide, our five-year capital expenditures projections, excluding AFUDC, but including retirement projects and expenditures are as follows, in 2016, $124.1 million; in 2017, $117.4 million; in 2018, $167.7 million; 2019, $160.9 million; and in 2020, $119.8 million. This capital expenditures plan does not contain any major changes from the plan we presented at this time last year. The 2016 and 2017 projected expenditures return to more of a maintenance level of capital spending, providing a break for our customers from the rate increases resulting from our Asbury and Riverton projects. It also provides an opportunity for us to catch up some of the regulatory lag that we experienced during that time. Capital expenditures ramp up again in 2018 and 2019, as we focus our spending on customer reliability, communications and efficiency initiatives. As you can see from the slide, with this capital expenditures plan, we continue to project rate base growth at about a 4% compounded interest rate over the next five years. We’re using our net plant levels, net of deferred taxes to approximate our rate base levels. In addition, we have not assumed any bonus depreciation beyond 2014, nor have we assumed any expenditures related to the clean power plant in our projections. As we have seen historically, this net plant increase realized from building rate base infrastructure will drive our earnings growth. Turning to our recent regulatory activities, slide 11, summarizes the key aspects of our just-filed Missouri rate case and provides you with the docket number under which our testimony is filed. As Brad stated, we’re seeking a $33.4 million increase in base revenues which is about a 7.3% increase. The test year, we have filed ends June 30, 2015. We have requested an expense true-up through March 31, 2016, assuming an in-service date of June 1 for the Riverton 12 project. Our requested return on equity in this case is 9.9%. Using a consolidated capital structure of approximately 51% to 49% debt equity, we applied a 7.58% rate of return to our filed Missouri jurisdictional rate base of $1.368 billion to arrive at our operating income requirement. Our solar program compliance costs are also included in this Missouri rate filing. Last quarter, we reported on the launch of a mandated solar rebate program for customers. As of September 30, we had received about 250 rebate applications, totaling around $3.4 million in rebate-related costs. This represents approximately 3,300-kilowatts of solar capacity. These costs have been deferred onto our balance sheet. Similar to our previous rate case to recover our Asbury expenditures, we will experience a period of lag between the in-service date of the Riverton conversion and the time when the new customer rates are put in place. Assuming the Missouri Public Service Commission’s 11-month procedural schedule, new rates would become effective in mid-September 2016. Finally, on slide 12, we have a summary of our other regulatory and legislative filings, we have made since the first of the year, including our October 26 filing with the Oklahoma Corporation Commission for the reciprocal rate approval of the customer rates in our new Missouri filing which Brad talked about. I’ll now turn the discussion back over to Brad. Brad Beecher Thank you, Laurie. We continue to execute on our environmental compliance plan. As I mentioned earlier, the Riverton combined cycle unit is on track for completion in early to mid-2016. Once operational, the high efficiency of the unit will help us hold down fuel costs while lowering emissions and protecting the environment. In August, the EPA released its final rules for the clean power plan. The overall objective of the plan is to reduce nationwide carbon dioxide emissions by 32%, below 2005 levels by 2030. The next step is for individual states to develop compliance plans or partner with neighboring states on collaborative plans which are due to the EPA in September of 2016. A two-year extension for submitting final plans is available. We’re actively working with state environmental agencies to encourage the development of a regional plan. We have attended multiple meetings and workshops in Missouri, Kansas and Arkansas and are engaged on a national level through our membership in the Edison Electric Institute. We will continue our focus on the development of a least cost compliance option for our region, while also ensuring our ability to effectively utilize existing generation resources located across the multiple states we serve. In our southeast Kansas area earlier this month, local officials joined us in the dedication of a new electrical substation. The $4 million project is part of our ongoing initiative to strengthen the energy delivery system and enhance reliable service for our customers. This is one of several reliability upgrades being completed across our service area. Plans for the development of a new medical school in Joplin are still on track. Earlier this year, Kansas City University of Medicine and Biosciences announced plans to develop a medical school in Joplin, using the 150,000 square-foot building previously used by Mercy Hospital. Use of the existing structure will allow the medical school to open in the fall of 2017 with an estimated 600 students when the college is full. Most important to our business, the medical school is estimated to have an annual regional economic impact of over $100 million per year once it reaches full maturity. With that, I will now turn the call back to the operator for your questions. Question-and-Answer Session Operator [Operator Instructions]. And our first question will come from Brian Russo of Ladenburg Thalmann. Brian Russo Just curious, the September 2016 for new rates effective in Missouri, that assumes it goes the whole 11 months and isn’t settled? Laurie Delano That’s correct, yes. That would be the 11-month jurisdictional time period in Missouri. Brian Russo Okay. What was the timeframe from when you filed the last case? From when new rates went into effect? Laurie Delano This last case, it was just right at about 11 months. Brian Russo Okay. Got it. Laurie Delano In the past, we have sometimes settled earlier. But not always. Brian Russo Okay. I think in the case you just filed, you think you mentioned a 49% equity ratio. Laurie Delano Yes. Brian Russo Okay. What’s the equity ratio embedded in rates currently? Laurie Delano I believe it’s a little bit higher than that, around 50%, but not very much different from that. Brian Russo Okay. Then when I look at slide 9 – this might be a difficult question to answer. But is there – can you point to one or two years where your CapEx is more normalized, meaning you don’t have any major projects hitting the income statement and creating lag? Just to get a sense of kind of what’s kind of the structural lag you just have with the historical test year? Brad Beecher Brian, I don’t know that there are any years within this period we’ve got in front of you where we didn’t have something major going on. In 2008, 2009, 2010, obviously we had all the expenses piling up for IO-102 and Plum Point. 2011, we had the tornado. Then 2012 was relatively small, but then we start ramping into Asbury AQCS pretty shortly thereafter. Brian Russo Just, is there any way to weather normalize 3Q 2014 sales or load – because obviously, you had a year-over-year favorable variance due to weather. Just want to get a sense of the – what kind of normalized load growth this is looking like? Brad Beecher For this quarter that we just completed for third quarter 2015, I would say that overall, our total sales were pretty much what we expected from a weather normal standpoint. We had a little bit higher commercial and less than – and less than what we expected residential which kind of evened out. But, in the past we’ve talked about the fact that we think our annual weather normal sales or about 5 million-megawatt hours. We’re not seeing any major change to that. Brian Russo Okay. And did you see – did you experience any impact from the new hospital and several new schools that became fully operational in the third quarter? Laurie Delano We’re seeing that. I think our press release kind of lays some of those numbers out. We’re seeing an uptick in our commercial sales and that’s a lot of what’s driving that, particularly the hospital. Again, our residential sales are a little bit below what we expected. I think we’re seeing some of that energy efficiency come into that. Operator And the next question is from Paul Ridzon of KeyBanc. Paul Ridzon Your $150 million into Riverton 12, is that what you said? Brad Beecher Yes. Paul Ridzon At this point, do you have any clarity on kind of which end of that $165 million to $175 million range you might end up in? Brad Beecher We’re still finishing up the project and there’s quite a lot of things can happen. We’ve not changed that range as we have, as we talked to the market or to the Public Service Commission. Operator And the next question comes from Julien Dumoulin-Smith of UBS. Julien Dumoulin-Smith Following up a little bit on that a lag question, can we just get a little bit more articulate about your expectations on this rate case relative to the last and the year-over-year comps is you kind of think through the next case? Is there – I suppose maybe the first question out of the gates is, is there any reason to think that lag would shift structurally in this case versus the last for any discreet reason? Brad Beecher There is no change in law, so as soon as Riverton 12 goes into service, we’ll start depreciating it. We will experience that lag until we get new rates on both depreciation and property tax. Laurie Delano One thing to keep in mind. I think maybe it’s on the slide, the Riverton depreciation rate will be a little bit lower than that Asbury rate was, more in the 2% range, whereas Asbury was in a 5% range, just because we’ve got a longer life on this Riverton project. So that will be one of the differences. But the depreciation will still start when it goes into service. Julien Dumoulin-Smith Right. So realistically speaking, you’ve got a few months, call it 1Q 2016 you’re not taking the depreciation impact. You get the year-over-year rate case benefit, you go in for the 2Q and 3Q, in which you’re booking depreciation against the asset. In theory, that should be the worst of the lag phenomenon. Then by 4Q, you should have the new rates in effect which are offsetting the D&A? Is that broadly a good way to think about it? Laurie Delano That would be correct. Julien Dumoulin-Smith Excellent. Then just what is your latest, given the sales growth trends that you just described in terms of quote-unquote, normalized lag, if you will? Obviously, the first quarter coming out of a new rate case will be the top. But how good can it get? Laurie Delano The basis points in lag, is that what you’re – Julien Dumoulin-Smith Exactly. How small of a lag can you get? Laurie Delano Julien, absent a change in law, change in the way our customer energy usage is happening, I think our historical pattern of ups and downs that you see on slide 9 is a good indication of what we can achieve on both ends of the spectrum. Julien Dumoulin-Smith All right. Excellent. Any other comments about changes at the commission? I would just be curious if there’s anything afoot, policy-wise, et cetera. Brad Beecher Julien, I don’t know that there’s a whole lot of things new policy-wise. One thing that we’re looking forward to Kansas City was, had a requested some moneys for energy charging infrastructure for electric cars in their last case, that the commission declined to make a decision on. So I think that kind of policy decision may be coming in the future. We clearly keep watching ROE and ROE trends and those kinds of things at the commission. Operator [Operator Instructions] Showing no further questions, I would like to turn the conference back over to Brad Beecher for any closing remarks. Brad Beecher Thank you very much. Our management team remains dedicated to our long-term strategy as a high quality pure play regulated electric and gas utility, pursuing a low-risk rate base growth plan, managing a diverse environmentally compliant energy supply portfolio and maintaining constructive regulatory relationships in each of our jurisdictions. We’re committed to meeting today’s energy challenges with least cost resources, while ensuring reliable and responsible energy for our customers and an attractive return for our shareholders. We will be at the EEI Financial Conference November 8-10 in Florida. We look forward to seeing many of you there. As always, we appreciate you sharing your time with us today. Have a great weekend. Operator The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.

Guard Against Rising Rates With These ETFs

The latest Fed meeting saw mixed reactions from investors. As expected, the Fed remained dovish on rate issues citing a slowing job market, moderating U.S. economic growth, subdued inflation and most importantly, a shaky global market. All these issues were discussed in the September meeting itself and the investing world had pushed back the timeline of the lift-off to early next year, presuming a delayed U.S. economic rebound. But to their utter surprise, the Fed kept the December timeline on the table. A keen watch on employment and inflation data is now crucial for the U.S. monetary policy in the December meeting. After all, the global market turmoil has eased now with the Chinese economy resorting to fresh rate cuts and the ECB hinting at a stepped-up QE measure. The dual dose was sturdy enough to bring the global economy back on the growth path and encourage the Fed to mull over a December hike. Investors rapidly shifted their bets with futures contracts entailing a 43% December hike possibility compared with 34% preceding the statement. In anticipation of a faster lift-off, the 10-year Treasury bond yields jumped 14 bps to 2.19% in the two days (as of October 29, 2015). Given this, investors might seek to safeguard themselves from higher rates. For them, we highlight a few investing strategies and the related ETFs: Say Yes to Zero or Negative Duration Bonds Rising rates result in increasing losses for bonds since bond price and yields are inversely related to each other. As a result, zero or negative duration bonds are less vulnerable and better hedges to rising rates. Negative duration bond ETFs offer exposure to traditional bonds while at the same time short Treasury bonds using derivatives such as interest-rate swaps, interest-rate options and Treasury futures. The short position will diminish the fund’s actual long duration, resulting in a negative duration. As a result, these bonds could act as a powerful hedge and a money enhancer in a rising rate environment. The zero duration funds include the WisdomTree Barclays U.S. Aggregate Bond Zero Duration ETF (NASDAQ: AGZD ) and the WisdomTree BofA Merrill Lynch High Yield Bond Zero Duration ETF (NASDAQ: HYZD ) while negative duration funds include the WisdomTree Barclays U.S. Aggregate Bond Negative Duration ETF (NASDAQ: AGND ) and the WisdomTree BofA Merrill Lynch High Yield Bond Negative Duration ETF (NASDAQ: HYND ) (read: Negative Duration Bond ETFs: Right Time to Bet? ). Stick to Floating Rate Bond ETFs A floating rate note is a bond with a coupon that is indexed to a benchmark interest rate. Some of the popular benchmarks include LIBOR and Treasury rates. Since the coupon is adjusted to reflect market interest rates, at a regular interval, these bonds are less sensitive to increases in rates compared with traditional bonds with fixed rate coupons, which lose value as the rates go up. The i Shares Floating Rate Bond ETF (NYSEARCA: FLOT ) and the SPDR Barclays Capital Investment Grade Floating Rate ETF (NYSEARCA: FLRN ) are some of the floating rate bond ETFs to watch. Cycle into Cyclical Sectors Investors should note that rising rates are synonymous with economic improvement. Cyclical sectors like technology and consumer discretionary should perform better ahead. The Market Vectors Retail ETF (NYSEARCA: RTH ) and the PowerShares Dynamic Leisure & Entertainment Portfolio ETF (NYSEARCA: PEJ ) are a couple of consumer discretionary ETFs to watch. The SPDR S&P Semiconductor ETF (NYSEARCA: XSD ) and the PowerShares Nasdaq Internet Portfolio ETF (NASDAQ: PNQI ) are technology ETFs that investors can try out. Most importantly, a rising rate scenario is a great backdrop for financial ETFs as this corner of the market should soar on improving interest rate margins. This is because banks borrow money at short-term rates and lend the capital at long-term rates thereby benefitting from a widening spread between long- and short-term rates. Financials ETFs like the Financial Select Sector SPDR ETF (NYSEARCA: XLF ) and the SPDR S&P Bank ETF (NYSEARCA: KBE ) are some of the financial ETFs to be considered for gains (read: Guide to the 7 Most Popular Financial ETFs ). Withdraw Rate-Sensitive Sectors There are a few sectors that are highly associated with the Fed’s interest rate policy. Sectors like utilities and real estate are known for their high dividend payout and require huge infrastructure, leading to an immense debt burden and the consequent interest obligation. As a result, these sectors underperform in a rising rate environment. So, investors need to turn aside these sector ETFs or rather bet on inverse utility or real estate ETF to cash in on rising rates. The ProShares UltraShort Utilities ETF (NYSEARCA: SDP ) and the ProShares Short Real Estate ETF (NYSEARCA: REK ) are some of the opportunities in this field. Satiate Income Need with High Yield ETFs In this backdrop, yield-loving investors might be looking for ways to beat the benchmark Treasury yield and yet enjoy decent capital gains. Senior loan, preferred stock and business development ETFs could fit the bill for high-yield seekers. Senior loans are issued by companies with below investment grade credit ratings. In order to make up for this high risk, senior loans normally have higher yields. Since these securities are senior to other forms of debt or equity, senior loans give protection to investors in any event of liquidation. The PowerShares Senior Loan Portfolio ETF (NYSEARCA: BKLN ) and the Highland/iBoxx Senior Loan ETF (NYSEARCA: SNLN ) are examples of two senior loan ETFs yielding 3.97% and 4.23% as of October 29, 2015. Preferred stocks are hybrid securities having characteristics of both debt and equity. The preferred stocks pay the holders a fixed dividend, like bonds. These types of shares normally get priority over equity shares both in case of dividend payments as well as at the time of liquidation if the company fails. Preferred stocks are thus relatively stable and usually exhibit a low correlation with other income-generating assets. The iShares S&P U.S. Preferred Stock ETF (NYSEARCA: PFF ) yields about 6.02% as of October 29, 2015. Business Development Companies (BDCs) are firms that loan out to small- and mid-sized companies at relatively higher rates and often grab debt or equity stakes in those companies. BDCs dole out high cash payments together with capturing the equity performance of the borrower. The U.S. law obliges BDCs to hand out more than 90% of their annual taxable income to shareholders. The Market Vectors BDC Income ETF (NYSEARCA: BIZD ) yields 9.03% as of October 29. 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