Tag Archives: author

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.