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AES Tiete’s (AESAY) CEO Britaldo Soares on Q1 2015 Results — Earnings Call Transcript

Executives Britaldo Soares – CEO Francisco Morandi – VP, CFO & IRO Analysts Lilyanna Yang – UBS AES Tiete SA ( OTCPK:AESAY ) Q1 2015 Earnings Conference Call May 11, 2015 10:00 AM ET Operator Welcome to the conference call for AES Tiete SA operated by Chorus Call Brasil. In this conference call we will be discussing the results for the first quarter of 2015. The IR area of AES Tiete also informs that the release is available at the company website at ir.aistiete.com.ar. [Operator Instructions]. On behalf of AES Tiete we would like clarify that any statements that may be made during this conference call regarding the business outlook, projections and the company’s operating and financial targets are only predictions based on current expectations. Such expectations can change as a result of variable such as market conditions, economic performance and international markets. The presentation can be downloaded on the webcast website and will be made by Britaldo Soares, CEO and Mr. Francisco Morandi, VP & IRO. At the end of the officers are available for questions. I will now like to give the floor to Mr. Britaldo Soares, sir you have the floor. Britaldo Soares Thank you very much. Good morning everyone. We will now start the presentation for AES Tiete first quarter of 2015. I will briefly summarize the main aspects and Francisco Morandi, our IRO and CFO will provide you with general overview in more detail. Today we also have VP for Generation, [indiscernible], the VP for Operations of Generation, Italo Freitas, VP for Legal Affairs, Pedro Bueno and our team for IROs. Going on to slide 2, we have the highlights for the first quarter 2015. The hydrological scenario is adverse and we have had the negative dispatch and that has marked our market. The inflows was 64% and lower than the long term targets. The reservoirs closed at an average rate of 30.2% of their capacity compared to 40.5% in the first quarter of 2014. The average reduction of the ERM was 20.7% compared to 3.9% in the first quarter of 2014. In consolidated terms we had a generation of energy equivalent to 61% of the physical guarantee and I would like to remind you that in the first quarter of 2014 this will give us 92%, as a result of a very severe hydrological condition and this has been faced by the entire national network. We’re still trying to our operational processes and the management of our assets AES Tiete has become the first company in the Americas in the electricity sector to obtain the ISO 55000 in order for it’s asset management program of it’s hydropower plant including the generation of it’s reservoir and support schemes concerning the commercialization of energy we have sold in this quarter 9 megawatts to deliver in 2017 and between 2019 at an average price of R$200 per megawatt hour our long term vision for the 2017, 2019 period is between a R$190 to R$200 per megawatt hour as of 220 the price will probably approach the marginal cost of inflation and will be around 160 megawatt per hour, our contraction position Eletropaulo totaled 83%, 74% and 47% in 2004 and 18% respectively and this has given us more flexibility as of 2016. Moving on to slide 3, we have the main points of our financial and economic results. The net revenue for the quarter totaled R$690 million a reduction by 9% compared to the first quarter of ’14 due to mainly the lower volume of energy sold in the stock market compensated by the larger volume of AES Eletropaulo and allied to the GSE and the strategy for seasonality. The price of energy bought at stock price impacted significantly the operational cost and expenses in order to cover the ERM. In terms of the cost, the manageable PMSO we achieved a reduction of 16% compared to the first quarter of ’14. This reduction results from our efficiency measures, asset management and cost in the last year. Our EBITDA this quarter totaled 392 million and this absorbs the impact of the reduction of the ERM and the effects of the seasonality between the first quarter of 2015 versus the first quarter of 2014. We closed the quarter with net income of R$200 million and we have approved and proposed in the Board of Directors of a 122.4 million in dividends to be paid on May 25. Francisco Morandi will now take this presentation on and we will talk and give you more details on the AES Tiete performance. Francisco Morandi Thank you, Britaldo. Good morning everyone. We are now moving to slide number 4, you can see the evolution of the reservoirs and the thermal dispatch. You see that in the first quarter of 2015 with 62% of the historical average and including April it goes to 67% of the historical average. If you compare this performance to the inflow of 2014 which was 64% you see a reduction of two percentage points including the month of April, the inflow was 68%. For your reference the inflows recorded in the quarter for 2014 was 80% of the historical average. When we see the evolution of the reservoirs at the IN, we see that in March we attended 30% of the useful volume. The reservoirs today are at 35% capacity, on the right hand side of the slide we have the evolution of the reservoirs and a thermal dispatch in the last years. You can see that the thermal dispatch is still high totaling 17.5 gigawatt in the first quarter for 2015, the same volume for the fourth quarter of 2014 and higher than the last period in the last year. If you go on to slide number 5, you can see the main information on the level of reservoirs in AES Tiete and the generated energy. You can see that the volume of reservoirs of our plants closed the quarter with 59% compared to 44% in the first quarter of 2014. The position today is 74% of reservoirs today. You can see on the chart that there was an improvement in terms of the reservoir levels of the main plants of the company however in the Southeast market, in the center west you can see that there was a fall at the reservoir levels in the first quarter of 2015 if we compare with the same period of last year closing at 33% in the first quarter of 2014 and 19% in the first quarter of ’15. The inflow observed in this region was 58% of the LMT and 74% in the fourth quarter of ’14 compared to the inflows observed in this quarter with the same quarter of last year you can see that there was slight improvement because the inflow of last year’s first quarter was 52% concerning energy generated, you can see the thermal dispatch in the Southeast and the Central west when compared the generation in the same period of last year. As a reflex we have again 994 and 1902 which is equivalent to 60% of the secured energy for Tiete. On slide 6, we have some possible scenarios in term of reservoir levels for 2015 considering several possibilities in terms of the reduction of the load. As a result of internal assessment we see that the rationing risk in 2015 is reduced at 8% concerning a reduction in the lows of 0.5% to 1%. The company believes the price on the stock market will remain at a ceiling of R$388.46 per megawatt hour across the throughout the year and at the thermal dispatch will total 16 to 17 gigawatt average. The GSF for 2015 is estimated between 0.81 and 0.83. In the next slide number 7, you see the reduction in the ERM for 2015. The reduction verified in the first quarter of 2015 was 20.7% this amount was the period to the amounts recorded for the first quarter of last year which was 3.9%. As a result both of the increase of the thermal dispatch and of the seasonality strategy in the market, concerning our hydrological projections for 2015 we’re forecasting the maintenance of a high level of reduction in the MRA. As a result we’re reviewing our GSF and a possible impact in EBITDA for the year. The provision for the thermal dispatch should be at 16% to 17% at gigawatt [ph]. And this will total a stock price of top R$388 throughout 2015. The company also previews [indiscernible] that the 20 [ph] exchange of the subsystems and the intermittent generation. The load that should previously grow by 0.7% should be reduced by 0.5% to 1%. As a result the company has reviewed it’s estimates and expects a reduction by 17% to 19% as we have said our GSF between 0.3% 83, that will maybe result in an impact negative impact of 750 million to 840 million in EBITDA in 2015. On the next slide we see the specific results both for billed energy, or invoice energy and for net revenue. The company’s billed energy grew 1% when compared to quarter-on-quarter mainly due to increase on billed energy in the contract with AES Eletropaulo which is partially offset in the spot market in other [indiscernible] contract. The net revenue in the first quarter in turn totally R$690 million in the first quarter 9% down from the same period of last year due to the seasonality strategy and also due to the GSF. On the next slide, slide number 9, we’re talking about costs. The light blue part in the chart shows mainly the impact of cost on the purchase of energy in the first quarter of 2015 when compared to the first quarter of 2014. As we can see growth of cost in the first quarter of this year is related to a higher purchase of energy in the spot market, despite the fact that we had a lower price when compared to the same period of last year. The important piece of news is that if we continue to intensify our efficiency gains initiatives and also in-line with our guidance which was published in the end of 2014 we have reduced PMSO, the manageable PSO by 16% in the first quarter when compared to the first quarter of last year. Process review the also internalization of labor and services and also the reassessment of administrative cost were the main drivers leading to that reduction level, all efforts are in-line with our strategic guidelines for disciplined execution and efficiency in the use of resources. For 2015 the company will continue to work so that the manageable PMSO will grow zero when compared to the year 2014. Moving on to slide number 10, we can see that the EBITDA for the first quarter totaled R$392 million as opposed to 594 million in the first quarter of last year and this quarter the company recorded a net income of R$200 million vis-à-vis R$358 million in the first quarter of 2014. The main drivers for that performance in the quarter are, the reduction in the period, the seasonality strategy even with gains in manageable cost and an increase in the contract price with Eletropaulo. The company’s Board of Directors approved last Friday a dividend payout of R$122.4 million that correspond to a 100% of the distribution base. On slide number 11, we will be talking about investments. Investments in the first quarter totaled $30 million when compared to R$37 million invested in the first quarter of 2014. Most of that were allocated to the modernization and maintenance of [indiscernible] plans. Additional on the same slide we can see our investment plans for the 2015, 2019 cycle with investments at $487 million mainly allocated to modernization and maintenance of the company’s power plant. On the next slide, slide number 12, we see that the generation of cash flow was at R$101 million driven by higher purchase of energy in this spot market also reflect of reduction of fiscal guarantee any difference is not a strategy when compared to 2014. Free cash in the first quarter of 2015 was negative R$221 million as opposed to 164 positive in the first quarter of last year. With that our final cash position in the first quarter is R$280 million. Moving on to the next slide, we see that the company’s leverage level closed the first quarter 1.9 times reflecting again the seasonality. And also due to the reduction in the period, our net debt closed the quarter at R$1.4 billion as opposed to R$0.8 million in the first quarter of 2014. Mainly due to the issuance of the second promissory note at R$500 million which will be partially used to amortize that throughout the year. The company amortized the last installment of the first debenture issuance a 120 million were paid on March 31, and 180 million were paid on April 1st. On slide number 14, we see the contracting level for the company’s own energy, the company has signed new contracts in the first quarter of 2015 with a volume of approximately 9 megawatt average at an average price of R$200 per megawatt hour and an average term of three years. After those sales the contract level reached 83% in 2016, 74% in 2017 also 74% and then 47% in 2018 which places the company in a very comfortable position and prepared to face a new scenario which will come after the out of the contract with Eletropaulo which will happen at the end of this year in 2015. As it was anticipated by Britaldo, our price expectation for the period ranging from 2017 through 2019 is very strong R$190 and R$200 per megawatt per hour. Starting in 2020 prices will come closer to the marginal cost of system expansion sitting at around a R$160 per megawatt hour. I give the floor back to Britaldo for his final remarks. Thank you. Britaldo Soares Thank you, Francisco. As you could see during the presentation our hydrological conditions have stayed below historical average so that the adverse scenario and high levels of thermal dispatch resulted in a lowering of the physical guarantee of the ERM which led to a higher purchase of this in the spot market and that in turn affected the results of the company in the first quarter. We carry on looking for more efficiency in our operations as we see a drop of 60% in manageable cost which was reaffirmed by Francisco during the presentation that’s one sign of our efforts and also to improvement of our operating processes such as those including maintenance of our assets which are now been recognized by the ISO 55001 relative to our contracting strategy, our contract portfolio after 2015 will remain consistent which should reach a level of 83% in 2016, 74% in 2017 and 47% in 2018. As Francisco also said in the end, our vision is for a price range for three year contract of around R$190 to R$200 per megawatt hour for the 2017-2019 period and looking in the longer term 2020 and on we’re looking at a price at around R$160. We will now move to the Q&A session and we will be available for your comments and doubts. Thank you very much. Question-and-Answer Session Operator [Operator Instructions]. Our first question comes from Lilyanna Yang from UBS. Lilyanna Yang I would like to know if you still have any ongoing negotiation on the generators part concerning GSF which is very high for this year and if you have any forecast for that GSF level for next year as well. Thank you. Unidentified Company Representative As for the GSF our proposal consist of restricting the economic impact then on by generating companies to a certain level. For example 5% and we’re also assessing alternatives to mitigate whatever exceeds that level. In our view there is a series of variables which are out of the control of generating companies and which we will interfere in the dispatch level for example. That some of dispatch for electricity safety and also the out of merit [ph] dispatches or dispatches which are not taking place in a centralized way and also variations in consumption, that’s slowdown consumption in fact generating companies to the extent that we don’t have good reservoirs levels. So the tone of dispatch is maintained and thermal electric generation absorbs that reduction due to — I will give you an idea the out of merit dispatch for this year is expected to reach something above 7% in terms of — that will impact the actions for generating companies by 7% so it is essential for us to establish a limiting level for that. And that will also help us to allocate cost that occasionally exceeds those levels, so that we can share risks and benefits of that scenario. Lilyanna Yang Can you give an idea of the level of out of merit generation for last year? Do you’ve that number at hand? Francisco Morandi I don’t have any but I can get it for you, the out of merit generation for last year. Britaldo Soares Cyrino [ph] gave you an overview of what we have been discussing. Of course there is a very positive aspect to emphasize which is the following. When we talk to the ministry of mines and energy when we talk [indiscernible], the regulating agency we see a clear concern on the part of the ministry and on the part of the regulating agency to deal with the GSF issue because of the impact it has in generating company. It is a relevant impact as was said to-date it is recognized by everyone and that is no doubt an evolution in the process. We can of course there are challenges for us to implement a solution but I can tell you that today as we see it there is a genuine interest on the part of the ministry, on the part of our NIO [ph] they are getting ready to start, the public hearing cleared as you know to deal with this issue. So in what concern the mechanism itself we have several ongoing discussions, there are several points which were raised during this discussions some of them are with more resonance of this [Technical Difficulty] resonance and that is typical of that type of situation when you’re discussing how to adjust such a relevant impact. But again clearly what you can see that both the ministry and the regulating agency trying to converge in terms of finding a solution to tackle that impact of a GSF generation. What I can tell you now is that we have high expectations that this will be resolved. Hopefully with special mechanisms as defined, okay? Thank you. Operator The next question comes from [indiscernible] and it’s a web question. Unidentified Analyst What is the status for the restructuring of Brasiliana. Is there an update concerning the schedule of the process? Britaldo Soares When we have any change and use on the Brasiliana issue we will announce this to the market that everything we have already said in a previous announcement and any new negotiations between shareholders that results and impacts AES Tiete we will duly announce it to the markets. Operator The next question comes from [indiscernible]. Unidentified Analyst I have a question about the strategy of the commercialization of the company, this 83% level, is this a ceiling for this year compared to the contracted level and concerning the strategy that the company has this low level of contracted energy recorded, is this a trend or should we expect an increase for the following quarters? Unidentified Company Representative For 2016 in a situation we have today for the reservoirs in April we will be closing 35% and the certainty that we have terms of hydrology how the reservoirs will be in the rain period. The idea is to keep at this level of this contracting level for a flexibility in 2016 and as we see the development of the conditions of the system we may change this level but for the time being we are seeking to contract the period after 2016 for contract beginning in 2017 in order to work on the contracted levels as of that date. Operator [Operator Instructions]. The next question comes from Lilyanna Yang from UBS. Lilyanna Yang One question about your thermal project, you’ve signaled recently that you could be participating in the A5 auctions for the gas Thermo plants at the Sao Paulo plants, how do you see gas prices behaving and what kind of structure will you need should you decide to do it? Unidentified Company Representative We have our main project is so called Thermo Sao Paulo which was certified by the M5 [ph] auction but because of the gas contracts that we have we will structuring a contracting of imported liquefied gas, and then we will be using the terminals and the [Technical Difficulty] of course we will be paying for that using that cost structure did not fit the ceiling price which we defined as 2.81 per kilowatt hour that’s why we did not participate on the A5 auction on our April — last April but we’re trying to develop new opportunities going through new negotiation so that we could have a project which would be closer to that price level and of course we also went for the government agencies to recognize that — if we have to bring the gas from abroad, if we do not have an associated terminal that cost structure needs to be reviewed. Lilyanna Yang Okay, just to understand, so it’s not the commodity price but a structure price that terminals and everything right? Unidentified Company Representative I would say the issue at the whole scenario, when you add all the costs in the chain for the gas under that solution we do not have a satisfying return. Britaldo Soares When you take carry on working to adapt those costs parameters to that [indiscernible] so that we can maximize the rules of those installations for regasification. Cyrino [ph] has been working on it and the idea is that we’re able to make that structure feasible in terms of cost. And would of course make all the projects feasible in the end. Operator The next question comes from [indiscernible]. Unidentified Analyst I would like to talk again about the GSF and I know that the scenario we feel looking for developments in the negotiations but in your scenario. Is the idea that any change in 2015 will affect the year or would it be as of a new methodology is developed or even if anything concerning last year since last year we did had a dispatch and a level of risk above the model and I would like to understand a little bit more about and hear from you what could be considered seeing that what has already affected the losses of the generators. Britaldo Soares Obviously Edwardo, that in our discussions and within the definitions and concept we have been discussing and that have been explained by Ricardo Cyrino [ph] this leads us to discussing what has already happened of the impacts that have been felt by the generators. So there is a retro-action therefore we’re discussing a retroactive aspect of a solution that has to encompass things that have already taken place no shadow of doubt in terms of that, in terms of a practical view this will all depend of the final understanding, of would this be in 2015, if this will go back and retroact to 2014 because in fact what we’re discussing the concept, they are not specific to the years 2014 or 2015 but they address the problem of the reduction, of the GSF and the causes of this as Ricardo listed, so it’s a conceptual discussion and as of that you then develop your line of thoughts. Obviously that in the negotiation as a process it may be designed that there is a starting date for this but being very pragmatic yes there is a risk to have a retroactive effect but the starting point in practice will depend in my point of view from a final understanding and of all the process that is taking place to discuss this at the ministry or at the regulator. Unidentified Analyst And Britaldo, do you’ve an idea when this will be finished? Britaldo Soares I believe that today we are focusing a lot both on the part of the regulator, both the ministry as well but it’s very hard to say a certain period of time it may take place in the first semester yes, but it really depends on the solutions. It’s a matter that is somewhat complex and depending on the structured measures there may be measures necessary that take time so it’s very hard to say but I see that the matter is developing at a much better pace and with much more efforts from the point of view of the ministry and an effort than in the past but even so it’s difficult to say a date because these things mature and they consolidate slowly. And it’s a solution that is complex. So thank you. Operator Next question comes from [indiscernible]. Unidentified Analyst I would like to understand the cost a little better, we see better numbers for cost this quarter, did any non-recurring item worth mentioning took place? Francisco Morandi Basically, Andre [ph] we saw a reduction in maintenance cost. This happened this quarter and impacted reduction PMSO. Unidentified Analyst So again it was — we could see those figures at the same level going forward, am I right? Francisco Morandi I think that looking at PMSO. Looking forward we will maintain the guidance, so yes so keep those costs in real terms at those levels, yes. Unidentified Analyst Okay, that would be a better way to look at PMSO look going forward. Operator There are no more questions I would like to give the floor back to Mr. Soares for his final remarks. Britaldo Soares Thank you all for participating in this call. We’re as always available for other queries or comments you may have. The whole team, our IRO, they are always available and at your disposal. Once again thank you and have a nice day. Operator AES Tiete’s conference call is now over. Thank you all for participating and have a nice day. Thank you. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. 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Northwest Natural Gas’ (NWN) CEO Gregg Kantor on Q4 2014 Results – Earnings Call Transcript

Northwest Natural Gas Co. (NYSE: NWN ) Q4 2014 Earnings Conference Call February 27, 2015 11:00 AM ET Executives Robert Hess – IR Gregg Kantor – President and CEO Steve Feltz – SVP and CFO Analysts Derek Walker – Bank of America Operator Good morning, and welcome to the Northwest Natural Gas Company’s Fourth Quarter Results Conference Call. All participants will be in listen-only mode. (Operator Instructions) Please note that this event is being recorded. I would now like to turn the conference over to Mr. Bob Hess. Please go ahead, Mr. Hess. Robert Hess Thank you, Dana. Good morning, everybody, and welcome to our fourth quarter and full year 2014 earnings call. As a reminder some of the things that will be said this morning contain forward-looking statements. They are based on management’s assumptions, which may or may not come true, and you should refer to the language at the end of our press release for the appropriate cautionary statements and also to our SEC filings for additional information. We do expect to file our 10-K later today. As mentioned, this teleconference is being recorded and will be available on our website following the call. Please note that these calls are designed for the financial community. If you are an individual investor and have questions, please contact me directly at area code 503-220-2388. Media please can contact, Melissa Moore at area code 503-220-2436. Speaking this morning are Gregg Kantor, President and Chief Executive Officer and Steve Feltz, Senior Vice President and Chief Financial Officer. Gregg and Steve have some opening remarks, and then will be available to answer your questions. Also joining us today are other members of our executive team, who will help answer any questions you may have. With that, let me turn it over to Gregg for his opening remarks. Gregg Kantor Thanks Bob. Good morning, everyone and welcome to fourth quarter and year-end review. I’ll begin today with an overview of 2014 and then turn it over to Steve to provide the financial details for the quarter and the year. I’ll wrap up the call with a look-forward. For Northwest Natural 2014 was a year of both opportunity and challenge. Last year our utility performance was solid, with improvements in customer growth and margin. However, those results were offset by losses associated with our gas cost sharing mechanism and the impact of natural gas prices. We also continued to see weakness in the California storage market hampering the financial returns from our Gill Ranch storage facility. In the midst to be varying factors, we delivered earnings of $2.16 per share and 2014 while providing a total shareholder return of approximately 22%. On the growth front, the Northwest economy made positive gains last year with Oregon’s employment rebounding to prerecession levels and unemployment rates continuing to fall. In 2014, we saw a healthy increase in commercial margins and an uptick in commercial new construction activity. The housing sector also improved with Portland home sales up nearly 4% and the average sale price up 7% last year compared to 2013. In addition, United Van Lines ranged Oregon its top moving destination last year, a positive indicator for future housing sector growth. And in Clark County in Washington, the fastest growing county in our service territory, home sales increased 8% with the average sale price increasing about 10%. These improvements help drive up our customer growth rate to 1.4% last year, and in the process we reached a new milestone adding our 700,000 customer. We believe last year’s healthy market improvements coupled with our substantial price advantage over electricity and oil put us in a strong position for additional customer growth going forward. In 2014 we made significant investments in safety and in reliability of our system. We completed several system reinforcement and facility upgrade projects and we continued our aggressive pipe replacement efforts. In fact we plan to remove the last three miles of bare steel pipe in 2015 making us one of the first utilities in the nation to eliminate both cast iron and bare steel pipe throughout our distribution system. In 2014, we reaped the advantages of having a more modern and robust system when extreme winter weather put us in the test. Last February we set a company record with a send out volume hitting 9 million firms in a 24 hour period. That’s almost double the normal send out for a typical winter day. And I’m pleased to report our pipeline system and storage facilities performed very well. I’m also pleased to report that for the fifth time in eight years we ranked first in the west in the annual J. D. Power Gas Utility Residential Customer Satisfaction Study. Last year also marks the seventh time in eight years that we were among the two highest scoring gas utilities in the nation. Now let me shift to the status of our regulatory agenda. Last year we continued to work through three remaining dockets carried over from our 2012 Oregon rate case. Just last week the OPUC issued its decision regarding how the Company’s environmental site remediation and recovery mechanism would be implemented. In the final order the commission found that all but $33,000 of the $114 million of environment remediation expenses incurred from 2003 through March of 2014 were proved. However due to the application of an earnings test from 2003 through 2012 the OPUC disallowed recovery of expenses totaling $15 million. At the same time the order specifies that insured settlements totaling over $150 million were entered into prudently by the Company. Steve will provide more details on how the mechanism works but let me just say that while the write down is disappointing we view our ability to fully recover future environmental cleanup cost as the key issue in a very complex and tough docket and we’re pleased the environmental spend and insurance settlements were deemed prudent. We do have some questions and implementation issues that we will be working on with the commission, but overall we believe the order provides us with a reasonable path forward. We expect the last two proceedings from our 2012 rate case to also be decided on this year. These are the interstate storage sharing and pension dockets. As you know, last year we amended our gas reserves agreement with Encana in response to their sale of the Jonah field. While the new arrangement ended the original drilling program, it also increased our working interest in Jonah and allows us to continue to invest in the field on a well by well basis. Under the new agreement, in 2014 we invested in seven wells and yesterday we filed with the OPUC to recover those costs as part of our utility hedge portfolio. A final important regulatory milestone last year was the filing of our integrated resource plan in Oregon and Washington. The plan covers a variety of issues associated with our ability to serve customers, including the need for additional system investments in Clark County, Washington and at our Newport LNG plant in Oregon. Just a few days ago we received acknowledgement on the IRP from the Oregon commission and we expect to receive notification from the Washington commission by this summer. With that let me turn it over to Steve. Steve Feltz Thank you, Gregg and good morning everyone. In 2014 we made significant progress on a number of fronts, including operational improvements and some important long term growth initiatives in both the utility and gas storage businesses. Additionally as you’ve heard earlier we received an order from the OPUC on how we would recover future environmental costs, which was a significant financial issue carried over from our last rate case in 2012. I’ll talk more about the financial implications of that order later on. But first let me turn your attention to 2014 results. Earnings for the fourth quarter were $1.04 per share on net income of $28.5 million. That was down slightly from $1.07 per share on $29 million a year ago. Results for the quarter reflect an increase in utility earnings largely due to higher margin and lower operating and maintenance expense. The utility increase was more than offset by a decrease from our gas storage segment which was driven by the re-contracting of Gill Ranch capacity at lower prices due to the depressed market conditions in California. The utility realized margin gains despite significantly warmer weather and lower customer usage. During the quarter, temperatures were 25% warmer than average and delivered volumes were down 13% compared to a year ago. The steady margin gains from our utility reflect our consistent customer growth and the effectiveness of our weather normalization and decoupling mechanisms. Now turning to full year results, consolidated earnings were $2.16 per share on net income of $58.7 million in 2014, as compared to $2.24 per share on $60.5 million a year ago. From the utility, net income for 2014 was $58.6 million, up from $54.9 million a year ago. A $12 million increase in margin was driven by customer growth, incremental use by commercial customers on higher margin rate schedules and added rate base recovery from new investments. These margin gains more than offset the impact of weather, a $2.1 million loss from our regulatory gas cost incentive sharing mechanism in Oregon and a $3.2 million increase in depreciation expense. From an operational standpoint, total gas delivery by the utility decreased 5% to 1.09 billion terms. The decrease was largely driven by 13% warmer than average weather and by declining average use for the customer. Despite the 5% decrease in volumes, utility margin increased by more than 3% over last year, including adjustments totaling $19 million from our weather normalization and decoupling mechanisms in Oregon. From our gas storage segment, net income in 2014 was a loss of $400,000, as compared to a gain of $5.6 million a year ago. The $6 million decrease in storage net income primarily reflect an $8.9 million decrease in operating revenues and a $1.8 million increase in operating expenses. As mentioned earlier, the decline in storage revenues was largely tied to lower prices at our Gill Ranch facility in California. Meanwhile, operating expenses at that facility increased, partly due to higher power cost for storage resale following significant withdrawals from last year and higher repair cost. Recently we’ve seen some improvement in summer-winter spreads for the upcoming storage year and because we have short-term contracts for a majority for our capacity, we should realize slightly higher prices in California this year compared to last year. But despite this improvement, we expect continuing challenges in 2015 as current storage values remain lower than the pricing on our original multi-year contract. With regard to operating expenses, for the quarter our O&M costs were 8% or $3.1 million lower than the same period last year. On a full year basis, O&M increased by less than 1% compared to a year ago. The year-over-year increase was mostly attributed to the previously mentioned higher power and repair cost at Gill Ranch, but that was largely offset by lower payroll and other cost savings at the utility. Cash provided by operations during 2014 was $216 million, up from $176 million in 2013. The main differences from year ago were the receipt of $103 million from insurance proceeds partly offset by increases in the deferred gas cost due to higher prices and other changes to working capital accounts. The insurance proceeds in particular helped to improve our liquidity position. With respect to our gas reserves program, we invested $27 million in 2014. Of that total $10 million was under the new amended ownership agreement with Jonah Energy, which we refer to as our post carry well. We recently filed with the OPUC a request to recover the revenue requirement associated with the post carry wells, thereby adding these gas reserves to our utility gas hedge portfolio. Our investment in gas reserves, both from the original contract with Encana and under the new agreement with Jonah Energy totaled $187 million since inception. Before providing earnings guidance for 2015, I’d like to explain some of the financial impacts of the recently issued regulatory order on the recovery of past and future environmental costs. First, the order results in an immediate onetime $15 million pre-tax charge for past environmental costs which we’ll record in the first quarter of 2015. The Oregon commission disallowed this amount based on its determination of how an earnings test should apply to past years from 2003 through 2012. As part of its review, the commission ruled that all but $33,000 of the $114 million in total cost through March 2014 or were deemed to be prudently incurred. Second, the commission ordered that the insurance proceeds received by the Company which amount to about $150 million in total be allocated to past and future costs with one-third of the total supplied for the recovery of past costs through December 2012. The remaining two-thirds would be placed into a secure account earning interest with those amount supplied for the recovery of future cost. In the order, the commission also concluded that all insurance settlement entered into by the Company through March of 2014 for were deemed prudent. After applying roughly $50 million of insurance proceeds towards past costs and deducting the $15 million disallowance, the commission order allows for full recovery of the remaining balance of past cost through 2012, which amount to roughly $30 million. The $30 million of past cost will go into the recovery mechanism which allows for these costs to be collected from customers over a rolling five year amortization period beginning this year. In addition to recovery in our past cost from customers and insurance, the commission also ordered the full recovery of future environmental cost as follows. First, the company will recover the first $5 million each year from customers through a tariff writer effective 2013. The Company will then apply an additional $5 million from the insurance account plus interest accrued on the account during the year to the next portion of environmental cost also effective 2013. If our environmental costs are less than $10 million plus interest, then any unused insurance will roll forward into the next year. If however our annual environment costs exceed the $10 million plus any insurance roll forward from the prior year then the excess will be fully revered through the environmental recovery mechanism. However if the Company earns above its authorized ROE, then the Company would be required to use the amount of earnings above its ROE to cover environmental expenses greater than the $10 million plus any insurance roll forward. In effect the company is provided full recovery of its environmental cost going forward. Today the Company is initiating its 2015 earnings guidance in the range of $1.77 to $1.97 per share for 2015. After adjusting for the one-time $15 million pretax charge previously discussed our earnings guidance for 2015 is $2.10 to $2.30 per share. The Company’s 2015 guidance assumes customer growth from our Utility segment, average weather conditions, slow recovery of the gas storage market in California and no significant changes in prevailing legislative and regulatory policies or outcomes. With that I’ll turn the call back over to Gregg for his concluding remarks. Gregg Kantor Thanks Steve. In 2014 our utility performance was solid with improvements in customer growth and added rate based returns on gas reserves and other system investments. We also made progress on our other growth initiatives. Earlier this month we received approval from Portland General Electric to move forward with the permitting demand acquisition work required for a potential expansion project at Mist, our underground gas storage facility. The project would be designed to provide no notice storage services to PGE’s natural gas bio-generating plants at Port Westward in Oregon. The potential expansion would include a new reservoir providing up to 2.5 billion cubic feet of available storage, an additional compressor station with design capacity of 120,000 dekatherms of gas per day and a 13 mile pipeline to connect the PGE’s gas plants at Port Westward. In 2015 our team will be working to obtain all the required permits and certain property rights and assuming successful completion of those necessary elements the current estimated cost of the expansion is approximately $125,000 million with a potential in service date in the 2018, 2019 winter season, depending on I should say the permitting process in construction schedule. As you may recall Oregon passed a bill effective last year that allows the OPUC to incent natural gas utilities to undertake projects that will reduce greenhouse gas emissions. We view this legislation as an exciting opportunity to make a positive environmental impact while potentially serving our customers and communities in new ways. In 2014 we worked through a rulemaking effort with the OPUC staff and customer advocates rules for what we are referring to as the carbon solutions program were then passed by the Oregon Commission this past December. In parallel to that rulemaking effort last year we began assessing a number of possible projects spanning several areas. Examples of potential projects involve reducing methane emissions during pipeline maintenance and repair, residential oil conversion program and distributed generation projects that use natural gas to increase energy efficiency. At this point, we are refining concepts and meeting with interested stakeholders to discuss our ideas, including the OPUC staff, customer advocates and energy efficiency groups. Our goal this year is to file several projects with the Oregon Commission to consider and hopefully to approve. In my view the carbon solutions program offers an excellent opportunity for us to demonstrate our spirit of innovation to showcase the important role natural gas can play in helping our region meet its environmental goals and add to the Company’s bottom line. In the months ahead we intend to make progress in a number of areas as I’ve said, continuing to grow our utility customer base, completing the last two remaining dockets from our 2012 rate case proceedings, advancing the north Mist expansion project, and doing all of this while continuing to provide safe and reliable service to our customers. Thanks again for joining us this morning and now I’d be happy to open it up for questions. Question-and-Answer Session Operator We will now begin the question-and-answer session (Operator Instructions). Gregg Kantor It’s hard to believe we were that clear on all of this stuff, but it doesn’t appear there are any questions. We’ll wait another few seconds here. Operator Our first question is from Derek Walker of Bank of America. Mr. Walker? Derek Walker Just I appreciate the color going through the order on the environmental piece here. Just a quick follow-up and there was a lot of nuances to it about conditions associated with it, but I think in general in the past or at least at times you’ve been able to achieve little bit above sort of allowed ROE, but does this new mechanism effectively to limit your ability to go slightly above that, the 9.5%? Gregg Kantor It does in those instances where we spend more than what is in the in the tariff writer and the insurance. So we’re spending more than that amount, which is $10 million, it will limit going above our allowed return on equity. Derek Walker And as far as the — just given on the commodity backdrop, as far as additional wells being drilled is there — I guess what you’re seeing on that development side? Gregg Kantor Well, as I said in the remarks we do have the ability to drill on a well-by-well basis. But the way that works though is that Jonah Energy Inc. proposes wells to us and then we get to evaluate and make a decision about on a well-by-well basis whether we’re going to proceed with those wells. Right now there haven’t been any proposed to us, not exactly certain if there will be this year and again we take them on a well-by-well basis. I don’t expect that there will be — even if they do propose wells that they will be large. Again last year there were 10 that were proposed to us. So I don’t think that’s going to be a very large amount if there are wells proposed. The other part of it is that we continue to look at a second overall gas reserve deal as part of a discussion we’re having with the commission on what’s the right amount of gas reserves to have. We call that our hedging docket which was — is going to be open this year and hopefully completed this year and that will tell us whether we’ve got the right amount of gas reserves in our portfolio or not and hopefully we’ll get through that this year and it will give us some direction on a future deal. Maybe just a little bit more follow-up on the first part of your question Derek, which was about over earning, it does in most cases where we’re as I said spending more than $10 million, prevent us from over earning in those years. But I would also say that the important part of this docket I kind of want to underscore was the costs of this are large for the company in the future and our goal here was to make sure we got full recovery and the order does do that and we really believe that this is a very reasonable path forward for us. Operator (Operator Instructions). Gregg Kantor Well, if there are no other questions, thank you all for joining us this morning. We really appreciate your interest in our Company and look forward to seeing you down the road. Thanks. Operator The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. 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Empire District Electric’s (EDE) CEO Brad Beecher on Q4 2014 Results – Earnings Call Transcript

Empire District Electric Co (NYSE: EDE ) Q4 2014 Earnings Conference Call February 6, 2015 13:00 ET Executives Dale Harrington – Director, IR Brad Beecher – President & CEO Laurie Delano – VP, Finance & CFO Analysts Brian Russo – Ladenburg Thalmann Paul Zimbardo – UBS Michael Goldenberg – Luminus Management Tim Winter – Gabelli & Company Operator Welcome to the Empire District Electric Company Fourth Quarter 2014 Results Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Dale Harrington. Please go ahead, sir. Dale Harrington Thank you, Dan and good afternoon, everyone. I would like to welcome you to our year-end 2014 earnings conference call but let me begin by introducing Brad Beecher, President and Chief Executive Officer and Laurie Delano, Vice President Finance and Chief Financial Officer who in a few moments will be providing an overview of our 2014 results and our 2015 expectations as well as some highlights on other key matters. Our press release announcing 2014 results was issued yesterday afternoon. The press release and a live webcast of this call including our slide presentation are available on our website at www.empiredistrict.com. A replay of the call will be available on our website through May 6th of this year. Before we begin I must 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 disclosures in our SEC filings present a list of some of the risks and factors that could cause future results to differ materially from our expectation. I will 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 also available upon request or maybe 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 the presentation of gross margin each of which are non-GAAP presentations is beneficial for investors in understanding our financial results. And with that I will now turn the call over to Brad Beecher. Brad Beecher Thank you, Dale. Good afternoon everyone and thank you for joining us. 2014 was a good year for Empire shareholders. The one year total shareholder return was about 35.6%, record earnings record high stock prices, a strong balance sheet with improved retained earnings and a sustainable growing dividend that increased by 2% in the fourth quarter were highlights for the year. Today we will discuss further our financial results for the fourth quarter and 12 months ended December 31, 2014 period, recent activities impacting the company and our outlook for 2015. As shown on slide 3, yesterday we reported consolidated earnings for the fourth quarter of 2014 of 11.1 million or $0.26 per share compared to the same quarter in 2013 when earnings were 15.2 million or $0.35 per share. Earnings for the 12 months ended December 31, 2014 period were 67.1 million or a $1.55 per share. 12 months ended 2013 earnings were 63.4 million or a $1.48 per share. During their meeting yesterday the Board of Directors declared a quarterly dividend of $0.26 per share payable March 16, 2015 for shareholders of record as of March 2nd. In December we completed in-service testing for the Asbury Air Quality Control System. The Missouri Public Service Commission staff determined that as of December 15, 2014 the Asbury AQCS equipment hadn’t met the in-service criteria. The determination by the staff that the in-service criteria have been met is a vital step for the rate case we filed in Missouri on August 29th of last year. As you may recall in order for the commission staff to allow a December 31 true-up date it was required that that Asbury be in service prior to February 1, 2015. Recovery of costs associated with the Asbury AQCS is the primary component of the Missouri Case. I will remind you that we’re seeking the increased electric rates by about $24.3 million annually or about 5.5%. Missouri Commission staff has indicated in testimony filed January 29th that the true-up period for this case will in [ph] December 31, 2014. Local public hearings for this case have been scheduled for February 19 in Joplin and February 20th in Reeds Spring. The Missouri Commission has scheduled an evidentiary hearing at its offices in Jefferson City, the weeks of April 6 through 10 and April 13 through 17. In the interim the Missouri Commission staff will be conducting a construction audit and prudence review on the Asbury Project. True-up direct testimony is scheduled to be filed on April 30th and a true-up evidentiary hearing occur in May 13th. New customer rates as a result of this case will be effective no later than July 26, 2015. Initially we provided a cost estimate for the Asbury AQCS project without AFUDC of between a $112 million and a $130 million. We later updated investors that we expected to be in the bottom half of the range. Today as a result of solid project management I’m proud to report we expect cost to be around a 112 million without AFUDC and around a 120 million including AFUDC. In December we filed a request with the Kansas Corporation Commission for an environmental cost recovery rider, rates from our Kansas request will be effective no later than August 3, 2015. Additionally we plan to file a request for an environmental cost recovery rider in Arkansas later this month. In Oklahoma we filed a request on January 9th to amend our Southwest Power Pool Transmission Tariff. Our proposed amendment request the removal of a requirement to file a base rate case by July 2015. The SPP tariff was established in January 2012 to allow recovery of our Oklahoma share of transmission charges assessed by the Southwest Power Pool. A requirement of that tariff was that Empire must file a base rate case by July 2015 because of the Asbury Air Quality Control System completion in early ’15 and the Riverton 12 combined cycle [ph] conversion projects scheduled for 2016 and Oklahoma filing in 2015 would necessitate a second rate case filing in 2016. Since rate cases are costly for customers we are asking for this Oklahoma requirement to be removed. If our request is approved we would plan to file a single rate case in 2016 to capture costs from both the Asbury and Riverton projects. We announced yesterday that our 2015 earnings guidance falls within the weather normalized range of a $1.30 to a $1.45 per share down from our 2014 results of a $1.55 per share. The lower range reflects the full year of high expense primarily related to the Asbury AQCS upgrade and a new maintenance contract for the Riverton facility offset with only a partial year of new Missouri rates to recover their Asbury investment and other increased cost. I will now turn the call over to Laurie to provide additional details of our financials. Laurie Delano Thank you, Brad. Good afternoon everyone. I’m very pleased to be reviewing such positive financial results with you today, the information I would discuss today will supplement the press release we issued late yesterday and as always the earnings per share numbers referenced throughout the call are provided on an after-tax estimated basis. I will briefly touch on our 2014 fourth quarter results before I discuss our annual results. Our fourth quarter earnings of $0.26 per share reflect a more normal quarter of winter weather when compared to the previous year’s fourth quarter. They also reflect increases in operating and maintenance expenses when compared to last year. Slide 4, shows the quarter-over-quarter changes that impacted our earnings. Gross margins for revenues less fuel and purchase power expense decreased $1.5 million decreasing earnings by $0.02 per share quarter-over-quarter. We estimate the impact of the warmer weather and other volume metric factors compared to last year decreased revenue by about $3.2 million, decreasing margin by about $0.03 per share. This decrease was driven primarily by an 8.1% decrease in sales for our residential customers. Commercial sales were only down about 1%, the weather impact on commercial sales was mitigated in part of increased sales throughout our territory as well as increased sales at the New Mercy Hospital as it prepares to open in March. Increases in operating and maintenance expenses, decreased earnings about $0.06 per share driven by increased transmission operation and production maintenance expenses. Small changes in depreciation, AFUDC and other income and expense rounded out the remaining $0.01 per share decrease in earnings for the fourth quarter. Turning to our annual rates, as Brad mentioned earlier, our net income increased $3.7 million or $0.07 per share. Slide 5, provides a breakdown of the various components that resulted in this year-over-year per share increase. Consolidated gross margin increased $17.1 million over 2013 adding an estimated $0.25 per share. As shown on in the callout box on slide 5, we estimate that increased customer rates from our Missouri rate case effective in April 1 of 2013 added about $12.5 million to revenue or about $0.16 per share to margin. We estimate weather and other volume metric increases on the electric side of the business added an estimate $4.6 million to revenue year-over-year or about $0.05 per share to margin. The weather effect from the gas segment added about a penny per share. The volume metric change was driven by a combination of weather and higher commercial sales again including positive impacts from the construction of the New Mercy hospital. Increased customer accounts added an estimate $1.5 million year-over-year increasing margin about a penny per share. Changes in other miscellaneous revenues primarily related to SPP transmission revenues and non-volume fuel related items netted together rounded out the remaining increase in electric segment, revenues adding a combined net impact of $0.02 per share to margin. Increases in our consolidated operating and maintenance expense offset the positive margin impact decreasing earnings about $0.17 per share. The callout box on slide 5 provides a breakdown of this impact. As we’ve discussed on previous calls the largest individual O&M increase was for transmission operation expenses primarily related to SPP charges. This added expense reduced earnings about $0.08 per share. Increases in distribution and production maintenance along with general LIBOR cost combined to reduced earnings about $0.11 per share, other smaller cost increases reduced earnings to a total of $0.02 per share. These increases were offset by the effect of lower healthcare cost about $0.02 per share as well as the $0.02 per share positive effect of the regulatory reversal of a gain on sale of the assets that we recorded in 2013. And as you all will recall we also recorded a similar entry in 2013 for our planned disallowance. This 2013 write-off also has the impact of increasing earnings year-over-year by $0.03 per share. Continuing on with slide 5, depreciation and amortization expenses decreased earnings per share $0.05 driven by higher levels of plant and service and increased depreciation rates resulting from our April 2013 Missouri case. Increases in property taxes brought earnings down another $0.02 per share. Increased allowance for funds used during construction or AFUDC added about $0.06 per share to earnings reflecting our Asbury and Riverton construction projects. Small changes in other income and deductions in the effects of additional stock issued under our various stock plans round out the remaining $0.03 decrease in earnings per share. On our balance sheet we have $90.3 million in retained earnings as of December 31, 2014. We had $44 million of short term debt outstanding at the end of 2014 and we currently have $68 million outstanding. We received the proceeds from our $60 million private placement of first mortgage bonds on December 1. As Brad said we announced in our press release yesterday that we expect our full year 2015 weather normalized earnings to be within the range of a $1.30 to a $1.45 per share. Before I talk about the drivers for our new guidance I would like to review our actual 2014 results as compared to our original 2014 guidance. Slide 6 provides this information, in developing our 2014 guidance we assumed 30 year average weather, modest growth as Joplin continued the three building projects and the extra quarter of Missouri rates from our 2013 rate case and revenues from our 2013 Arkansas rate case filing. This was offset with a corresponding effect of increased O&M expenses. Our actual 2014 results of a $1.55 were higher than the midpoint of our original guidance range primarily due to one higher than expected electric and gas sales and two lower than expected operating and depreciation expenses. Higher sales added about $0.03 to our earnings per share on the electric side of the business, and about a penny to our gas segment results. Favorable weather and higher commercial sales again inclusive of the New Mercy hospital were the primary drivers. Decreased cost totaling $0.06 per share were driven by lower than expected generating plant operating expenses and lower than expected SPP charges. Also depreciation was lower due to the timing of various in-service dates of our construction projects. On slide 7 we highlight the drivers of our decrease in earnings expectations in 2015. First as in the past our estimates are based on normal weather with a modest positive sales growth as we have previously disclosed we still expect this growth to be at a level of less than 1% per year over the next several years. We’re also assuming our Missouri rate case will be effective as filed. We also assume our Arkansas and Kansas rate case filings will go into effect as filed. Operating and maintenance expenses will be higher primarily due to a new maintenance contract for our Riverton facility. Depreciation expense will increase reflecting the Asbury AQCS project in service for a full year and an estimated 20 year life rate and we will also see increased depreciation for assets placed in service since our last case. The impact on depreciation from the Asbury AQCS project alone is approximately $0.09 on an earnings per share basis. We will also see increases in property tax and interest expense. The higher interest expense reflects our December 2014 debt issuance and expected issuance in 2015. Our AFUDC impact will be lower in 2015 now that as Asbury is complete and in service. Other factors considered in our range are variations in customer growth and usage as well as variations in operating and maintenance expense. Again our range does not take into account any changes to our Missouri rate case filing or reflect any December 31, 2014 true-up numbers. As a reminder we have summarized the components of our Missouri rate case as currently filed on slide 8. On slide 9, we provide the historical and projected capital expenditures and net plant in-service numbers that reflect our current capital expenditure plan. No changes have been made since the update we provided last quarter. The 2015 expenditures reflect our ongoing cost for the Riverton combined cycle project. On this slide w also present our net plant levels less deferred taxes to approximate our estimated rate base. To finance these projects we expect to issue some debt financing in the middle of 2015. Right now we believe the debt offering will be in the range of $60 million but could be subject to change based on expenditure timing and other factors. This financing combined with the addition of internal equity from our dividend reinvestment and stock purchase plans and our combined build of retained earnings will help keep us near our target 50:50 debt equity capital structure. I will now turn the discussion back over to Brad. Brad Beecher Thank you, Laurie. As Laurie referenced and as shown in slide 10, in addition to the work completed in Asbury we’re moving ahead with construction at our Riverton power plant. The foundation work is complete and most of the major equipment is on-site for the Riverton Unit 12 conversion. As of December 31, our total cost of this project is 88.5 million. As a reminder we estimate our total cost of completion to be between a 165 million to a 175 million. We continue to successful execute our growth strategy to build rate base infrastructure to serve our customers and meet environmental regulations. The completion of the Asbury AQCS and on-going Riverton 12 combined cycle projects are the largest additions to these plan. Empire remains a high quality, pure play, regulated electric and natural gas utility. We’re focused on our vision of making lives better every day with reliable energy and service. We’re committed to meeting today’s energy challenges with least cost resources while ensuring reliable energy for our customers and attractive return for our shareholders and a rewarding environment for our employees. I will now turn the call back to the operator for your questions. Question-and-Answer Session Operator [Operator Instructions]. And our first question comes from Brian Russo of Ladenburg Thalmann. Please go ahead. Brian Russo When I look at kind of the midpoint of your 2015 guidance, kind of implies about an 8% earned ROE which is quite a meaningful amount of regulatory lag versus you know kind of 9-8 current allowed ROE. I just want to maybe drill deeper into the lag. I think you quantified the impact for the Asbury depreciation. Could we quantify the O&M impact as well and then kind of differentiate what structural lag versus what’s just timing lag related to your base rate cases. Laurie Delano We don’t really anticipate a huge O&M impact from the Asbury project, we will see an increase in our consumables, limestone, activated carbon and those sorts of things. However we actually recovered those back through our fuel adjustment. Obviously we will see an increase in property taxes from the Asbury project and if you look at the slide where our rate case summarization takes place you will see that we have asked for about $2.9 million in property taxes associated with that case. So that kind of gives you a feel for what that directionally might be. Brian Russo Okay, can you remind us of the lag that you experience on transmission cost and property taxes each year? Brad Beecher Today neither property taxes or transmission expenses are recovered in trackers and so they go through a normal procedure. So in this case what we’re recovering in our rates is reflective of the rates that we received in April of 2013. So, we have asked for in this current case the transmission expenses to be included in our fuel adjustment cost to help reduce that lag in the future. But that’s something that will have to be taken in account in this current case. Your other question, you had asked earlier relating to structural lag versus lag on timing of the cases. I have a hard time differentiating that, in Missouri we have a 11 month process and using this case is a good example for illustration is any – we have filed the case at the end of August of last year. We will expect rates by about July, we’re going to get a true-up through the end of the year and so that’s about as tight as we can cut it as it relates to the biggest CapEx expenditure. So we have 6 or 7 months lag on those big CapEx after they go in service before we get recovery in rates. And so that’s what we experienced on Asbury and we’re seeing today and it’s the kind of representative of the kind of lag we will see on Riverton 12 as well. Brian Russo Okay. In your last Missouri rate case you guys actually settled and rates went into effect in April. Was that several months earlier than the 11 month process or was the filing date different than this go around [ph]? Brad Beecher Brian, my memory is the rates went into effect a little bit early and when you get into settlement sometimes that’s one of the variables that we consider when we’re deciding whether to sell or not, it’s where the rates can go in a little bit early. I don’t recall the exact dates on the last case we will have to – we can dig that out later. Brian Russo Okay, so I guess if you did settled rates went into effect earlier obviously there would be less lag in ’15? Brad Beecher If that were to happen, that’s true. Brian Russo And then just back to your comment, the lag experience with Asbury this year and then the lag associated with Riverton upgrade next year. Is it kind of implied that you’re going to be experiencing similar regulatory lag in ’16 and ’15 and 2017 should be the year where we see improved returns? Brad Beecher What I was trying to get across is we’re going to have similar lag on Riverton 12 as we have on Asbury AQCS so that would say we’re going to have lag in 2016 and you can look at our CapEx forecast for ’16, ’17 and ’18 and we do drop off after Riverton 12 and that should give our shareholders a little bit of a better change to recover their allowed rate of return. Operator Our next question comes from Julien Dumoulin-Smith of UBS. Please go ahead. Paul Zimbardo It’s actually Paul Zimbardo. First question, on the estimated rate base slides, it looks like there is a little bit of a change from the last quarter, is that just bonus depreciation or something of alike? Laurie Delano For the rate base slides, yes, that would be correct. Paul Zimbardo And does that impact the rate case filing at all? Brad Beecher So, when we made the rate case filing bonus depreciation had not yet been extended and so our filing did not reflect that and same way when we put this slide together last quarter it had not yet being extended. So that accelerated depreciation will be reflected as one of the many true-ups that will happen at the end of the December 31 true-up. And as you pointed out bonus depreciation is a reduction or offset to rate base. Paul Zimbardo So a follow-up on the last question about quantifying some of those 2015 earnings driver, I apologize if I missed it, did you say what the impact of the new maintenance contract was– Laurie Delano I didn’t say but on the slide that summarizes our rate case filing assumptions, we call that out at $3.9 million. Operator [Operator Instructions]. Our next question comes from Michael Goldenberg of Luminus Management. Please go ahead. Michael Goldenberg So I want to go back to 2016, I understand 2015 is a big down year but I was under the assumption – I think we have discussed on a several occasion, you kind of always seem to point investors to when you think about long term, when you think about 2016, do rate base times equity times ROE and all these little changes in O&M are long haul, they even out and then structural lag probably should be more than let’s say a 100 bps that was kind of the impression that I think over the years have got. Is it fair to say that that may no longer be the best way to think about the company structurally? Brad Beecher If you look at the last several years for EDE we have been closer to 200 basis points regulatory lag and we have been looking at about 8% ROE in something that’s in that 10% kind of ROE range as people think about our allowed ROEs and so we have had closer to 200 basis points of lag historically. For 2014 we were at about 8.75% I think actually ROE, so we got down to about a 150 basis point to lag [inaudible]. In the big CapEx years we’re going to struggle a little bit more but as growth has come down in our industry and I’m really talking about our sales growth, it really tends to exacerbate regulatory lag when you don’t have any new kilowatt hour sales to help pay for increased expenses. Michael Goldenberg So help me understand this then, generally the way the rate cases work even with in stage with structural lag in your first year of rate case, let’s say it’s a three year cycle. Your drag is generally the lowest right when you get the rates and then I agree that if you have a lot of CapEx then by the end of year three that structural lag increases and that’s generally the way it works so. I kind of thought or was working on the assumption that if you take the period of July ’15 through June ’16, structure, that should be the time of your least drag. Is that not the right way or is the drag actually going to then get even worse? Brad Beecher I think you’re thinking about it correctly. Once our rates go into effect in ’15 until such time as we start big depreciation expense on Riverton 12 going into service, that will be the time of least regulatory lag in that kind of window, that year after you get rates and before you start depreciation and O&M on the new assets coming into service. Michael Goldenberg Okay and just to be precise, Riverton depreciation starts when? Laurie Delano Well we’re assuming that Riverton will come online in mid-2016 and so you would assume that deprecation would start immediately after it comes online Michael Goldenberg So then we would see drags of even more than 200 bps? Laurie Delano Well we haven’t really quantified that but – I mean it’s – you’re going to see the same, a little bit the same scenario again depending on what the depreciation amount is for Riverton and the other thing you see is AFUDC benefit dropping off when that plant comes into service, you know that’s happening on the Asbury project also. Brad Beecher And then as we’ve talked about earlier when the new plants come online we have got property taxes that get assessed [ph] and we have lag on property taxes as well. Michael Goldenberg But yes you get the revenue step up to make up for all of that and give you as much to the bottom-line as AFUDC used to, isn’t that the general concept, that when a plant goes into service. If everything is done ideally then revenue just increases for the amount that the expenses are and the net income stays roughly the same for a $1 off CapEx whether it’s AFUDC or cash. Laurie Delano Yes, when your rates go into effect that’s true but in those intervening months until they go into effect the time that plant comes online that’s where you’re going to drag. Michael Goldenberg And then just finally, conceptually thinking, yes it’s very good ’14 right? You made $1.55 and that’s before rate case, now you actually are going to get new rates and you do know how to CapEx and yet your earnings are going down and just judging by the structure of going into ’16 and then more depreciation. It’s hard to see how structurally putting in all this CapEx is actually – instead given the situation Missouri, does it actually incentivize investment where the company actually financially hurts from putting in more and more CapEx? Brad Beecher Well in the end our business model in Missouri is we earn a return on assets that we build to serve our customers. We’re going through structural pain and this is a perfect example, Asbury went into service. It’s been used to service customers, we’re depreciating it today and expensing it in early ’15. We’re paying property taxes, we’re paying O&M and we’re getting no recovery from customers until rates go into effect no later than July 26th and that is Missouri structural lag and it is a disincentive but it is the world that we live in. We’ve worked very, very hard in the Missouri legislature last couple of years trying to get some relief on plan in-service, trying to get relief on property taxes and we have so far being unsuccessful. Operator [Operator Instructions]. And another question just came in from Tim Winter of Gabelli & Company. Please go ahead. Tim Winter I just had one follow-up, Brad. Where is the legislation stand right now in Missouri to give property taxes and transmission expenses [ph] and whatever else included. Brad Beecher At the current time Tim to my knowledge there is not any legislation filed related to plant in-service and/or property taxes. We have got a lot of uncertainty in the state right now as the governor is got a statewide energy plan underway, I don’t know if you participated but there has been input meetings across the state and we would expect a statewide energy plan to come out sometime May kind of timeframe. We have got 111(d) and how that’s going to get finalized. So right now we’re still – I’m expecting a pretty quiet year in Jeff City, not saying that something can’t get done but I’m expecting a pretty quiet year in Jeff City, not saying that something can’t get done but I’m expecting a pretty quiet year in Jeff City as it relates to this topic. Tim Winter The statewide energy plan include something about – would address this issue? Because you’re not the only utility in the state that has this issue. Brad Beecher We’re absolutely not the only utility in the state with this issue. The statewide energy plan is comprehensive, it’s everything that you can think about from solar to distributed generation to responses and emergencies to what we need to build assets just about everything has been talked about in one work group or another. So, it’s a work in progress, it’s being led by a member of the governor staff and so we will have to see where it goes. But we certainly brought up this concern. Operator And this concludes our question and answer session. I would like to turn the conference back over to Brad Beecher for any closing remarks. Brad Beecher Thank you. Before we close I remind you that Laurie and I will be at the UBS Analyst Day in Boston on March 3rd and 4th and Laurie and Dale will be the AJA Mini-Forum in Dallas on March 17th and 18th. Also we will be saying goodbye to Jen Watson at the end of April as she has decided to retire. Jen has served Empire in the Secretary and Treasurer positions since 1995. We thank Jen for her service and wish her the best. The Board has named Dale Harrington to replace Jen as Secretary beginning May 1, 2015. Dale will also continue in this role of Director of Investor Relations. Thank you for joining us today and have a great weekend. Operator The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. 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