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Lipper Fund Flows: Gains For All Groups

By Patrick Keon Lipper’s fund macro-groups (including both mutual funds and exchange-traded funds [ETFs]) experienced aggregate net inflows for the fourth consecutive week-taking in over $56 billion of net new money during that time. The groups had positive flows of $24.8 billion for the fund-flows week ended Wednesday, October 28, paced by money market funds, which had net inflows of $15.7 billion. The other macro-groups all posted gains for the week as well; equity funds took in $8.4 billion of net new money, while taxable bond funds (+$432 million) and municipal bond funds (+$349 million) recorded more modest increases. The Dow Jones Industrial Average (+3.6%) and the S&P 500 Index (+3.5%) both posted strong performance numbers for the week. The indices were bolstered by improving economic data on the home front, stronger-than-expected corporate earnings reports from the technology sector, measures to ease global growth concerns, and the Federal Reserve’s leaving the window open to a possible interest rate hike before year-end. The week got off to a roaring start as both indices pocketed roughly 2.8% in combined gains during the first two trading days. Strong U.S. economic data and talk of more quantitative easing in Europe were the triggers on Day One. U.S. existing-home sales posted strong numbers for September (+4.7%), while new applications for unemployment benefits were at near-40-year lows. Across the pond, European Central Bank President Mario Draghi stated that the central bank may extend stimulus measures if global growth continues to be a concern. The rally continued on Day Two as tech companies Alphabet Inc., Microsoft Corp., and Amazon.com all posted stronger-than-expected earnings, while China announced a surprise interest rate cut (its sixth in less than a year) in an attempt to revive its slumping economy. The market experienced another bump on the last trading day of the week when the Fed hinted that the long-awaited interest rate increase may finally arrive in December. The Fed indicated that the global landscape will become less of a concern in December’s discussion, and the determining factors will be the next two monthly jobs reports (the Fed is looking for some additional improvement) and the inflation rate (for which the Fed has set a 2% target). The week’s net inflows for money market funds (+$15.7 billion) represented the fifth week in six of positive flows, which brought over $55 billion of net new money into the group. Institutional money market funds (+$11.6 billion) and institutional U.S. government money market funds (+$8.6 billion) were the two largest contributors to the week’s gains. Equity ETFs were responsible for the lion’s share of the net inflows (+$8.2 billion) for the equity group, while equity mutual funds contributed $221 million to the total. The SPDR S&P 500 Trust ETF (NYSEARCA: SPY ) (+$2.5 billion) and the Health Care Select Sector SPDR ETF (NYSEARCA: XLV ) (+$769 million ) had the two largest individual increases on the ETF side. For mutual funds-contradicting the trend we’ve seen all year-nondomestic equity funds had net outflows for the week (-$339 million), while domestic equity funds had positive net flows (+$560 million). Mutual funds were responsible for all the net inflows for taxable bond funds (+$660 million), while ETF products saw $228 million leave their coffers. Lipper’s High Yield Funds and Core Plus Bond Funds classifications (+$787 million and +$570 million, respectively) recorded the two largest net inflows on the mutual fund side. For ETFs, two Treasury products had the largest individual net outflows: The iShares 7-10 Year Treasury Bond ETF (NYSEARCA: IEF ) (-$602 million) and the iShares 3-7 Year Treasury Bond ETF (NYSEARCA: IEI ) (-$410 million). Municipal bond mutual funds took in $148 million of net new money-for their fourth consecutive week of positive flows. Funds in Lipper’s High Yield Municipal Bond Funds classification (+$181 million) accounted for all of the week’s net inflows.

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.

Pinnacle West Capital’s (PNW) CEO Don Brandt on Q3 2015 Results – Earnings Call Transcript

Pinnacle West Capital Corporation (NYSE: PNW ) Q3 2015 Earnings Conference Call October 30, 2015 12:00 PM ET Executives Paul Mountain – Director, IR Don Brandt – Chairman, President and CEO Jim Hatfield – EVP and CFO Jeff Guldner – SVP, Public Policy, APS Mark Schiavoni – EVP and COO, APS Analysts Dan Eggers – Credit Suisse Greg Gordon – Evercore Ali Agha – SunTrust Robinson Humphrey Michael Weinstein – UBS Brian Chin – Bank of America/Merrill Lynch Charles Fishman – Morningstar Paul Ridzon – KeyBanc Capital Markets Michael Lapides – Goldman Sachs Paul Patterson – Glenrock Associates Operator Greetings, and welcome to the Pinnacle West Capital Corporation 2015 Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Paul Mountain, Director of Investor Relations. Thank you sir, you may begin. Paul Mountain Thank you, Christine. I would like to thank everyone for participating in this conference call and Webcast to review our third quarter 2015 earnings, recent developments, and operating performance. Our speakers today will be our Chairman and CEO, Don Brandt, and our CFO, Jim Hatfield. Jeff Guldner, APS’s Senior Vice President of Public Policy and Mark Schiavoni, APS’s Chief Operating Officer, are also here with us. First, I need to cover a few details with you. The slides that we will using are available on our Investor Relations Web site, along with our earnings release and related information. Note that the slides contain reconciliations of certain non-GAAP financial information. Today’s comments and our slides contain forward-looking statements based on current expectations and the Company assumes no obligation to update these statements. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. Our third quarter Form 10-Q was filed this morning. Please refer to that document for forward-looking statements, cautionary language, as well as the risk factors and MD&A sections which identify risks and uncertainties that could cause actual results to differ materially from those contained in our disclosures. A replay of this call will be available shortly on our Web site for the next 30 days. It will also be available by telephone through November 6th. I’ll now turn the call over to Don. Don Brandt Thank you, Paul and thank you all for joining us today. Pinnacle West delivered a solid quarter with several financial and operational highlights keeping us on pace with our guidance for the year and setting us up well for next year. The Board also approved the 5% dividend increase last week effective with the December dividend payment, continuing the predictable return of capital to our shareholders. Jim will discuss the financial results and guidance. Our operations team did an excellent job maintaining the fleet and the electrical grid again this summer. The Palo Verde Nuclear Generation Station performed well. Unit 2 entered its planned refilling outage on October 10th this outage marks an important milestone. It represents the completion of flex equipment installation at all three units. Flex addresses one of the main safety challenges at Fukushima the loss of cooling capability and electrical power resulting from a severe event. Flex short for diverse and flexible mitigation strategies is an industry wide initiative with site specific applicability, it relies on portable equipment to protect against even the most unlikely scenarios. The transmission distribution and customer service teams also performed well. Similar to last year we had a series of monsoon storms over the last few months 50,000 customers were without power during the worse storm. The vast majority were back on within 24 hours. Due to the storm damage our crones replaced 485 pools nearly twice a number from the 2014 storm season. August was particularly hot this year. We hit our 2015 load peak on Saturday August 15th after temperatures hit over 114 degrees for three consecutive days. This is the first time in modern era with air-conditioning that our peak has been on a Saturday. One data point worth noting is that when our customers were using the most energy at around 5 pm that day rooftop solar on our system was producing only 38% of its capacity, supplying 75 megawatts of the 7,031 megawatt load, since rooftop solar peaks around noon. However in stark contrast utility scale solar was producing 80% of its capacity supplying 140 megawatts of the load, because most utilities scaled panels are on trackers that move with the sun. Just a couple of hours later when our system load was still high rooftop solar production was at zero and the only solar production was coming from Solana our concentrated solar facility with thermal storage capabilities. This scenario was not unique to our peak lower day and highlights the importance of the electric grid at all hours of the day. Along with a robust and modern grid modernizing the rate structure is a necessary priority for which we have been advocating. Let me provide some perspective on how our recent regulatory fillings have evolved. Our priority remains clear we want to continue the dialogue on rate design with the objective of thoughtfully evaluating these policy issues ahead of the rate case application we plan to file in June of next year. The grid access towards filling we made on April 2nd was designed to take another step in this rate transition by increasing the fixed charge to $3 per KW or about $21 per month per solar customer. In August the Arizona Corporation Commission ordered to move forward with an evidentiary hearing on the issue the exact scope and timing of that process was to be determined they has another meeting. Subsequent to that decision we saw an unprecedented display of political theatre and character attacks by the rooftop solar lobby aimed at paralyzing the commission. Given the backdrop we offered an alternative to the commission in September to forgo of the request to increase the grid access charge and exchange for a more narrow hearing on the cost to serve customers with and without solar. In connection with this alternative we filed a summary of a recently concluded cost to service study on October 8th. This study used a methodology that has been tried, tested and validated in utility proceeding across the country using actual verifiable data. It concluded that each month APS incurs $67 to serve solar customers that those customers do not pay. This analysis credit solar customers for the measurable cost that APS avoids when a customer installs rooftop solar primarily reduce fuel costs. The commission discussed how to proceed at the open meeting last week. In the end they wanted to move forward with a single generic docket that will investigate a both the cost to service issue raised by APS and the value of solar. The procedural calendar would be determined soon by the commission staff. Although there has been a lot of noise around this issue we believe moving forward is critical and we will continue to work with the commission and key stakeholders in this proceeding. In addition to the regulatory proceedings we are also learning about the customer and grid impacts through our solar partner rooftop solar program. Our understanding in this area will better inform our efforts to create a modernized rate structure tailored to our customers’ energy needs. We’ve had a lot of interest in the process of signing up customers and installing rooftop systems. Let me know provide an update on a few other items related to our generation portfolio. Our utility scale program AZ Sun has two 10-megawatt projects in the Phoenix metro area come on line in September bringing the total program total to 170 megawatts. We will access a need for more utility scale solar through our resource planning process. We also retired Cholla unit 2 one of our core units as of October 1st in line with our announcement a year ago as part of a broader environmental plan for the Cholla site. Let me conclude by saying that we remain focused on delivering on our financial and operational commitments. We have a busy calendar over the next couple of years while the state addresses rate design modernization and we prepare for our rate case filling. We will remain steadfast to find solutions that benefit all of our customers. I’ll now turn the call over to Jim. Jim Hatfield Thank you, Don and welcome everybody. We had a solid third quarter as we benefitted from our continued cost management efforts and improvement in our customer sales. Today I’ll discuss the details of our third quarter financial results provide an update on the Arizona economy and review our financial outlook including introducing 2016 guidance. Slide 3 summarizes our GAAP net income and ongoing earnings. For the third quarter of 2015, we reported consolidated ongoing earnings of $357 million, or $2.30 per share, compared with ongoing earnings of $244 million, or $2.20 per share for the third quarter of 2014. Slide 4 outlines the variances in our quarterly ongoing earnings per share. I’ll highlight two primary drivers. Higher gross margin increased earnings by $0.28 per share. I’ll cover the drivers of our gross margin variance on the next slide. Going the other way higher depreciation and amortization expenses decreased earnings by $0.12 per share. Similar to the first half of this year the variance includes the absence of the 2014 Four Corners cost deferrals and related 2015 amortization of the deferrals and cost associated with the acquisition. D&A expenses were also higher due to additional plant service. Turning to Slide 5, I will cover a few of the key components of the net increase of $0.28 in gross margin. Higher usage by APS customers compared to the third quarter a year ago contributed $0.08 per share. Weather normalized retail kilowatt hour sales after the effects of energy efficiency, customer conservation and distributed generation increased 2.1% in the third quarter of 2015 versus 2014. Collectively the adjustment mechanism is continuing to add incremental growth to our gross margin as designed, contributing $0.17 per share primarily the Four Corners adjuster that went into effect on January 1. Offsetting Four Corners’ expenses are included in the other drivers, primarily D&A, which I mentioned earlier. The effect of weather variations increased earnings by $0.04 per share. This year’s third quarter was warmer or more favorable than normal, while the third quarter of 2014 was milder, or less favorable compared to normal conditions. As Don mentioned, August was particularly hot this year or for the first time since we added in Arkansas — we hit our peak on a weekend. As a reminder, both the O&M and gross margin variances exclude expenses related to the renewable energy standard, energy efficiency and similar regulatory programs, all of which are offset by comparable revenue amounts under adjustment mechanism. Slide 6 presents a look at the Arizona economy, and our fundamental growth outlook. Arizona’s economy continues to grow, much like it has in the past several quarters. Job growth in the third quarter in the Phoenix Metro area remained above the national average, as they have for the past 17 quarters. As seen in the upper panel of Slide 6, Metro Phoenix added jobs at a 2.8% year-over-year rate. This job growth is broad-based with the construction, healthcare, tourism, financial activity, business services and consumer service sectors, each adding jobs at a rate above 3%. Growth in consumer spending remains robust and expectations are improving for the housing market. Our expectation for the Metro Phoenix housing permits could be seen in the lower panel on Slide 6. The housing market is on track to record its best year since 2007 for both total permits and the single-family sector by itself. Total permits are up more than 12% this year and notably single family permit activity is up over 40%. Permit activity in the third quarter was the highest we’ve seen since the middle of 2007 and homeowners continue to report strong traffic in their sales offices. In summary, Metro Phoenix economy did grow fairly and is positioned for stronger growth in the next couple of years as it will act on the overbilled real estate market receipts into the past. As I have mentioned before, Arizona and Metro Phoenix remain attractive places to live and do business, especially as it is situated relative to the high-cost California market. 2015 is turning out to be better than 2014 in terms of job growth, income growth, consumer spending, and new construction. And we expect 2016 to be better than 2015. Reflecting the steady improvement in the economic conditions, APS’s retail customer base grew 1.3% compared with the third quarter of last year. We expect that this growth rate will gradually accelerate in response to economic growth trends I just discussed. Importantly, the long-term fundamentals supporting future population, job growth and economic development in Arizona appear to be in place. Finally, I will review our earnings guidance and financial outlook. We continue to expect Pinnacle West’s consolidated ongoing earnings for 2015 will be in the lower half of the range of $3.75 to $3.95 per share, based on the negative effects of weather through September. Year-to-date unfavorable weather through September has impacted earnings by approximately $0.08 per share versus normal conditions. We adjusted our 2015 customer growth down slightly to 1% to 2% from 1.5% to 2.5%, although our sales outlook hasn’t changed. We are introducing 2016 ongoing guidance of $3.90 to $4.10 per share which assumes the normal weather. The adjustment mechanics particularly transmission and LFCR along with modest sales growth are the key growth margin drivers. O&M is above trend in 2016 however, non-outage O&M spending remains flat in 2016 compared to 2015 with planned possible outages representing the increase year-over-year. This includes major planned outages at Four Corners and Cholla which occur roughly over six years. Separately the new lease terms related to the Palo Verde waste plant at Unit 2 that take effect January 1, 2015 offset plan and service impact and key depreciation and amortization relatively flat year-over-year. A complete list of the factors and assumptions underlying our guidance is included in our slides. Our rate based growth outlook remains 6% to 7% through 2018. We’ve included our updated rate based slide in the appendix. These estimates include bonus depreciation which we’re assuming will be extended for 2015 and 2016. And we continue to forecast that we will not need additional equity until 2017 at the early. Lastly as Don discussed the Board of Directors increased the indicated annual dividend last week by $0.12 per share or approximately 5% to $2.50 per share effective with the December payment. This concludes our prepared remarks. Operator we’ll now take questions. Question-and-Answer Session Operator Thank you. We’ll now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Dan Eggers from Credit Suisse. Please proceed with your question. Dan Eggers If we get to see an end of the 2016 guidance a little bit. I guess first question is you go back from the 1.5% to 2.5% customer growth number, given that reduction in inventory and revenue mix. Is there enough things now are coming online for next year that you can actually hit that numbers you guys look out and see what’s getting built? Jim Hatfield We do Dan. We see as we talk about home permits were up 78% in the August from the same month a year-ago. We’re seeing sales up 32% in [indiscernible] so we’re seeing a lot of activity in that housing market. Don Brandt And this is Don, I refer you if you do a search on azcentral.com Web site for the Arizona Republic and just a story that appeared on the 21st of October I just take a selective quote out of that but over the past two years approximately 11,000 building permits for single-family new homes have been issued annually and he said the expectation is that the number will reach 16,000 by year’s end. Dan Eggers And then on the O&M cost side for next year. The cost should be flat excluding the maintenance I guess what you said if we thought about what ’17 looks like how much of that extra maintenance gives us a way to just try and normalize that? Don Brandt Well don’t think ’17 will be as big as ’16 and when we look for rate case purposes we use a average of five years or so, so that all get blended out in the rate case. Dan Eggers The rate case will reflect that moving that with the ’17 numbers? Don Brandt Yes I mean we’ll get all of it because this is a sort of peak but we’ll get an average over several years as typically how they do it. Dan Eggers And then on the rate base forecast it includes another non depreciation act in the 18 rate case numbers now have a $400 million, what you guys do with the bonus depreciation cash and the activation company and the equity? Don Brandt Easy to fund CapEx, we’ll still be net negative cash from our fixed income securities to fund the CapEx but it does reduce our need. Jim Hatfield It will reduce our need for debt financing. Don Brandt Yes and we take bonus depreciations will be 70% of that reduction in CapEx the rest is really moving Ocotillo out to ’19 from ’18. Operator Our next question comes from the line of Greg Gordon with Evercore. Please proceed with your question. Greg Gordon My math shows that — I think my math shows that on the updated rate case forecast that 390 to 410 basically should more or less reflect the 9.5% to 10% ROE band on parent equity in 2016? Don Brandt That’s correct, right. Greg Gordon So yes that’s consistent with the way you thought about in the past? Don Brandt Correct. Greg Gordon So to the extend we lined up with the low-end or to high-end of that range thinking about the drivers on Page 10. Obviously this year we’re more towards the lower half because weather was mild. Is it fair to assume that the midpoint of your gross margin guidance range just assumes just a normal weather? Don Brandt Yes it includes normal weather as well as we’ve those adjuster mechanisms two things you — the other thing you’ll see from the gross margin perspective we’ve the negative transmission adjuster in 2015 which will have a positive next year. So we get the cumulative effect of that as well. Greg Gordon I guess I’ll step back and then ask higher level more open ended question. What are the key two or three factors that would cause you to end up at 410 versus that would cause you to end up at 390 i.e. high end of the range versus low end as you think about managing risk in ’16? Don Brandt I’ll take the higher end of the guidance to reflect a little higher sales growth and we’re currently planning. That would be the big driver. Greg Gordon Okay. And you file a rate case when and how and when is the — what’s the statutory time limit for a decision? Don Brandt We will file June 1 of 2016 typically there was a 30 days efficiency and there is the last case we did in 10.5 we expect probably it will last goal longer with the rate design in there it’s the statutory four month timeline but and Christmas around as you get days of the hearings and so on. Greg Gordon So the goal would be to have rates in place for the summer of ’17 but that could slip? Jim Hatfield Yes. And the perfect word we will have it at July 1 what the issue in the case on rate design changes and so on that would be an optimistic scenario I think. Greg Gordon But isn’t that the reason why you are trying to get a lot of that discussion down now and the context of these proceedings that Don just discussed. Jim Hatfield Exactly Greg. Operator Our next question comes from the line of Ali Agha with SunTrust. Please proceed with your question. Ali Agha Don so do you want that the commission decided to have these hearings on the generic basis and I know you guys have pushed for them to be more specific and focused on the cost of service side and is there a concern that while they go through the generic process and then when the rate case comes you’ve got to go through this once again but with more specific numbers so at the end of the day how much realistically do you think this moves the ball forward given the generic measure of this discussion? Jim Hatfield I think it’s a new advanced the ball will be dealing with the not just generic number but our numbers specifically as will be other participants and Jeff Guldner sitting here next to me I think can explain on that far a little bit. Jeff Guldner Sure. And I remember this they said their value has sold the dockets which was up there with obviously would be a new port on a generic the cost of service study that we did is specific with us and so one of the things you would get in the generic proceeding is still some discussion of how do you apply cost allocation factors how do you sort it out cost to service issue and result those and move forward in the rate case with the given the commissioners policy options that are available to cost from the value side and the more of that we can work through ahead of the rate case the more productive that’s going to be when you get into the rate case process. Ali Agha And then secondly as strong was good to see the growth in weather normalized sales pick up this quarter at 2.1%. With customer growth at that 1.3% level was there anything specific to this quarter would the weather normalization not have worked perfectly the sense that your sales growth is actually greater than customer growth this quarter and normally as you said does that 50 to 100 basis point differential but you see so anything to explain why sales growth was strong than customer growth this quarter? Jeff Guldner I think the biggest thing Ali is sort of a weak comparison last year in the third quarter overall we have 1% sales growth year-to-date which would reflect the kind of customer growth we’re seeing currently. I think a lot of that two part of our we look at the we have top solar and EDE and a lot of this been confident it’s new and I think you are seeing a little more cost that consumer and those in the Phoenix marketplace. Ali Agha I see, okay. And then on a sort of the LTM basis based on the way you guys calculate ROE and I know that’s all book value when you talk about your targets. Can you tell us what is that ROE that you want over the LTM basis? Jeff Guldner I haven’t calculated that I’ll have to look at that. Ali Agha Okay. But to be clear on the ’16 outlook the range reflects at the lower end 9.5% again based on the book value calculation? Jeff Guldner Yes. Ali Agha And the high-end would be 10. Is that right? Jeff Guldner Yes. Ali Agha Thank you. Jeff Guldner Next question? Operator, next question? Christine? We have lost connection from the host just one moment please. Operator Ladies and gentlemen, I am sorry for the delay. Our next question will come from the line of Michael Weinstein with UBS. Please proceed with your question. Michael Weinstein Hi guys. Can you hear me okay? Hello? Oh! Boy. Operator Ladies and gentlemen, please stand by your conference will resume momentarily. Michael Weinstein Oh! Boy. Operator Ladies and gentlemen, again please stand by your conference will resume momentarily. Once again please stand by your conference will resume momentarily. Gentlemen, you are reconnected. And your next question comes from the line of Michael Weinstein. Please proceed with your question. Michael Weinstein Hi, guys. Can you hear me okay? Hello? I am not hearing anybody, operator. Operator Gentlemen you are connected. Michael Weinstein Yes, can you guys hear me okay? Don Brandt Yes. Michael Weinstein Oh! There we go. All right. Don Brandt Okay. Michael Weinstein So my question has to do with the guidance for 2015. Just looking at you’ve reduced the retail customer growth a little bit by 0.5% but the sales volume is remaining the same. So that would sort of indicate that there has been an improvement in terms of energy efficiency effects, I guess less of an energy efficiency effect that you see in 2015. However, when you go forward to 2016 guidance, you have an increase in the customer growth rate but still the same sales rate, so that indicates the opposite. Just wondering what’s going on with energy efficiencies and asset management side? Don Brandt I Michael would caution you to look at any quarter and try to extract anything out of quarters, a quarter. I think we are pleasantly surprised by the sales growth year-to-date. I don’t think we necessarily expect laying that into ’16 guidance. Michael Weinstein Okay. And also just in terms of the rate cases filing. Is it true you guys are going to have to file or you are going to have to make purchases of new generating assets before you file the case. Is that right? Don Brandt We have no plans to purchase generation assets other than what we are billing at occupancy or which is a self built. Michael Weinstein Okay, so there is no potential for anything else, fairly probably you can see now? Don Brandt No we have some PPAs and other things rolling off and we will go out next year for sort of all resources RFP for sometime later this — probably later this decade, then we will see what where get at that point but we’re ways off from new generation at this point. Operator Our next question comes from the line of Brian Chin with Bank of America/Merrill Lynch. Please proceed with your question. Brian Chin So with the revised rate base numbers including bonus depreciation, can you quantify out the impact of the bonus depreciation or give us some sense of how big that is relative to the prior forecast? Don Brandt Yes, bonus depreciation we expect to be over the two years about $250 million. We just think about that as ratably over those two years. Brian Chin Okay, excellent. And then with regards to the revised bonus depreciation numbers, can you give us an update on any potential needs for equity, I would assume that it reduces that since you are able to take the bonus depreciation and use that for further deployment of capital. But just revise us on what the equity financing needs are if any as we go to the next year? Don Brandt Yes, well, certainly the cash and bonus depreciation would minimize the need, if we need anything, we won’t do anything until after we get that outcome and next rate case. Brian Chin Okay, great. And then lastly, just what risk do you think there could be under the more narrowly tailored generic proceeding. Is it possible that any delays or extension of that proceeding could bleed into the timing of when you file the rate case? Is there a risk of the two issues kind of melting together? I guess it’s a little bit of a springboard question on earlier question I think that Ali asked? Jeff Guldner Brian it’s Jeff I don’t think it would affect the timing of the filing of the rate case. One of the issues that came up in the discussion a little while ago was we’ve requested that the information push to get that aside us in the April timeframe was ahead in the case. But the procedural conference is still coming out, if that leaves over that wouldn’t affect the filing, once you file the case you’ve got a fairly lengthy litigation process. Operator Our next question comes from the line of Charles Fishman with Morningstar. Pleas proceed with your question. Charles Fishman If I could go back to the rate base growth once again 2018, the 400 million decline in generation and distribution that was bonus depreciation and the delay of Ocotillo the $200 million decline in transmission is that all bonus depreciation or there a project is been delayed or canceled that I have forgotten about? Don Brandt No we’re constantly on ongoing basis moving capital from year-to-year so there is nothing substantial in terms of delay in big projects or anything like that. Operator Our next question comes from the line of Paul Ridzon with KeyBanc Capital Markets. Please proceed with your question. Paul Ridzon Very quickly, you said you had 2.1% sales growth and that is after the impact of efficiency correct? Don Brandt Yes, and distributors and origin. Paul Ridzon What was the gross number? Don Brandt Little over three. Operator Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question. Michael Lapides Sorry to beat a little bit of a dead horse just want to make sure I understand though. Can you walk us through from your prior disclosures to today’s flight deck, the change in total expected rate basis for the forecast period and just two or three biggest drivers for that? There has been a lot 1C 2Cs and I want make sure I understand what’s going on here? Don Brandt Well about 70% of the change roughly is the impact of bonus depreciation, and significant amount of the other is just moving Ocotillo from our end service date of ’18 to 2019. Michael Lapides And the total change is $400 million or greater number? Don Brandt About $4 million. Michael Lapides Second when we think about 2017 O&M should we assume that it kind of gets back down in that year to something closer what you’ve guided to for 2015 or does it kind of stay at that elevated level that you’re going to see next year but that you recovering you’re expecting to get more recovery of that in rates? Don Brandt We’ve really not talked about any aspect of 2017 guidance Michael. Michael Lapides Is the 2016 increase in O&M viewed more as one time or viewed as recurring? Don Brandt Well I think it is — I would call it one time, and we do generation outage every year where it is based with significant overall at both quarters at 28 in the same year I could say that that number is elevated based on what we wouldn’t call it one time in any view. Michael Lapides And the case are going to filed in mid-’16 will that use a full year ’15 test year and what large if any known and measurables would be in there? Don Brandt We’ll try to let’s see what we had on the past which is the 2015 test year and any planned service 15-18 months then post patch your plan and there will be some things that are still under construction that won’t be done like the SCRs or Ocotillo allows them to recover some other mechanism. Michael Lapides Meaning you’re expecting to potentially get Ocotillo recovered in this even though Ocotillo is now not due online until 2019? Don Brandt No, we would not get Ocotillo in this rate case. Michael Lapides So this rate case is more about just managing lag and getting the FBRs in? Don Brandt I think this rate case is also a lot about the rate design issue which is how we align our 70% of fixed cost with only 10% of fixed revenue and try to get more alignment between cost and revenue. Operator Our next question comes from our Paul Patterson with Glenrock Associates. Please proceed with your question. Paul Patterson There was a court case in the Arizona Court of Appeal which overturned from the Arizona Corporate Commissions it was the case that didn’t involve you but in theory I guess there is some that are arguing that the solar access being out of the rate case could be — would it comply with the court of appeal ruling if you follow me. I am sure you guys are familiar with the case but whether — is this a new point that you have withdrawn your request or is there any risk if this I know the ACC is probably going to appeal it but if this decision were upheld is there any risk to you guys would respect to what would be the impact to you guys if it was upheld let me just ask it that way? Jeff Guldner So Paul this is Jeff Guldner. If you are referring that water company case involving infrastructure adjustor the commission have appealed that and if so court of appeals case they start review with the Arizona supreme court and with the case that what’s there was how the commission makes fair value findings which is somewhat unique that Arizona regulation how it makes their value findings in the context of adjustor mechanisms and things like that so we get them in rate cases we do typically fair value findings and provisions and almost everything that we do and so what I think folks are looking for right now is clarify some of the things that were in the court has appeals decision but it’s I don’t think that the supreme court is not yet excited whether to grant review and if they do I’m sure they will see mostly intelligence of state participating in that litigation. Paul Patterson Okay, right. But I guess what I’m wondering is if they grant review and I mean this ultimately is upheld where there would be any impact on what you guys have collected in riders or what have you with this access do you mean what would be — let me just ask you this way with reviewing impact on you guys when you look at the Arizona court of appeal’s decision what do you think the impact would be if we were up held? Jeff Guldner The part of the review on how you that to make fair value findings and those proceedings and I think most folks would expect the release to be prospective and so would be in highly to move forward with a different proceeding in terms of making fair value findings to which support whatever the court ultimately came out lift. We’ve had filed adjustors and one of the things that was mention that decision is a fuel adjustor which tracks expenses up and down fuel adjustors have been common in Arizona for decades and that opinion recognize with types of adjustors fine and as you get into different styles or different models for adjustor gets little more complicated and you guys figure out how you put the fair value piece it up. [Multiple Speakers] Paul Patterson So you guys have been fine with fuel adjustment that wanted to be something that would be impacted but would there be any other potential riders as something that we should think about as being potentially impacted or is it would you feel basically that you guys have the one that impacts that much. Is that what I’m getting at? Jeff Guldner Yes. We also look at all the riders and we look at how the fair value provisions and how we handle fair value in each of those cases and that litigated or implemented the rate cases and then if we have to make adjustments for the next rate case then we would. Operator We have no further questions at this time. I would now like to turn the floor back over to management for closing comments. Don Brandt Thank you, Christine. Thanks for joining us today. We apologize for the connection issues we had on the call. And we look forward to seeing most of you at EVI here in a couple of weeks. Thank you. Operator Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.