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TECO Energy (TE) Q4 2014 Results – Earnings Call Transcript

TECO Energy (NYSE: TE ) Q4 2014 Earnings Call February 09, 2015 10:00 am ET Executives Mark M. Kane – Director of Investor Relations Sandra W. Callahan – Chief Financial Officer, Chief Accounting Officer and Senior Vice President of Finance & Accounting John B. Ramil – Chief Executive Officer, President, Director and Member of Finance Committee Analysts Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division Paul Zimbardo – UBS Investment Bank, Research Division Paul T. Ridzon – KeyBanc Capital Markets Inc., Research Division Andrew Bischof – Morningstar Inc., Research Division Scott Senchak Operator Good morning. My name is Keisha, and I will be your conference operator today. At this time, I would like to welcome everyone to TECO Energy’s Fourth Quarter Results and 2015 Outlook Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. Mark Kane, Director of Investor Relations. You may begin, sir. Mark M. Kane Thank you, Keisha. Good morning, everyone, and welcome to the TECO Energy Fourth Quarter 2014 Results Conference Call. Our earnings, along with unaudited financial statements, were released and filed with the SEC earlier this morning. This presentation is being webcast; and our earnings release, financial statements and slides for this presentation are available on our website at tecoenergy.com. The presentation will be available for replay through the website approximately 2 hours after the conclusion of our presentation and will be available for 30 days. In the course of our remarks today, we will be making forward-looking statements about our expectations for 2015 and beyond and our integration of New Mexico Gas Company and the sale of TECO Coal. There are number of factors that could cause actual results to differ materially from those that we’ll discuss today. For a more complete discussion of these factors, we refer you to the risk factor discussion in our annual report on Form 10-K for the period ended December 31, 2013, and an updated and subsequent filings with the SEC. In the course of today’s presentation, we will be using non-GAAP results. There is a reconciliation between these non-GAAP measures and the closest GAAP measure in the Appendix to today’s presentation. The host for our call today is Sandy Callahan, TECO Energy’s Chief Financial Officer. Also with us today is John Ramil, TECO Energy’s CEO, to assist in answering your questions. Now let me turn it over to Sandy. Sandra W. Callahan Thank you, Mark. Good morning, everyone, and thank you for joining us today. We appreciate your flexibility with the revised date for our call, which was necessary in order to work through the accounting impact of amending our agreement to sell the coal company. We were in discussions with the purchaser, and it became clear that a revision to the selling price was necessary. And since the appropriate accounting was to reflect that impact in the fourth quarter, we rescheduled the call in order to make the required changes to our financial statements. Today, I’ll cover our financial results, what we’re seeing in the Florida and New Mexico economies, the sale of TECO Coal and 2015 guidance as well as the longer-term outlook. As usual, the Appendix to this presentation contains graphs on the Florida and New Mexico economies and reconciliations of non-GAAP to GAAP measures. In the fourth quarter, non-GAAP results from continuing operations were $45 million or $0.19 per share compared with $0.18 last year. GAAP net income was $10.8 million, which includes a loss in discontinued operations of $16.6 million reflecting impairment charges of $11.6 million and the operating results of TECO Coal. Net income from continuing operations were $27.4 million in 2014 and includes $17.6 million of charges, consisting of transaction and integration costs of $3 million related to the New Mexico Gas acquisition and the $14.6 million adjustment to deferred state income taxes related to the pending sale of TECO Coal. Excluding these items, the non-GAAP results for continuing operations were $0.19 per share. For the full year, non-GAAP results from continuing operations were $1.03 per share, 11% higher than 2013’s $0.91. GAAP net income of $130.4 million or $0.58 includes a loss in discontinued operations of $76 million, which largely reflects value impairments at TECO Coal. Net income from continuing operations was $206.4 million or $0.92 and includes $23.3 million of charges and net tax adjustments related to acquisition and sale activities. Excluding these items yields the non-GAAP results of $229.7 million or $1.03 per share. Tampa Electric reported slightly lower net income in the fourth quarter. While customer growth was a strong 1.6% and we had 1 additional month of higher revenues from a 2013 rate settlement, energy sales were lower due to milder weather resulting in fourth quarter revenues in 2014 about the same as the prior year. AFUDC increased this quarter with higher investment balances in the Polk conversion project and the related water project; and O&M expense was lower. The quarter-over-quarter increase in depreciation expense represented more than just the normal increase from additions to facilities. That’s because in 2013, fourth quarter depreciation had included the benefit of a full 12 months of lower amortization costs to retroactively reflect the change in software life agreed to a November 2013 rate case settlement. Weather patterns resulted in retail net energy per load in the fourth quarter that was 2.8% below 2013. Looking at degree days, which were 10% below normal and 12% below last year, you might expect energy sales to be off more than they were even with the customer growth we saw. In Tampa, we actually have both heating and cooling degree days in the fourth quarter. In this quarter, heating degree days were about normal and cooling degree days were well below normal, and that combination produced a milder impact on energy usage than the 10% and 12% degree days variances would suggest. Peoples Gas experienced strong customer growth of 2.3% in the fourth quarter, which was higher than our full year estimates. That was due to robust growth in several of the southwest Florida markets that had been the most impacted in the economic downturn, as well as substantial growth in northeast Florida. We saw higher therm sales to all customer segments, residential, commercial and industrial, as a result of the periods of cold weather in the quarter, as well as continued economic growth. On the expense side, O&M was lower in 2014 while depreciation was up. New Mexico Gas fourth quarter results benefited from customer growth and the start of the winter heating season even though it was actually milder than normal and milder than 2013. New Mexico Gas is much more seasonal than Peoples Gas, and the fourth quarter is a very strong quarter for them, which resulted in about $0.03 of accretion to our consolidated fourth quarter earnings. The other net segment is what we used to refer to as parent other. The net cost in this segment was higher in the fourth quarter compared to last year driven by interest expense at New Mexico Gas Intermediate, which is a parent of New Mexico Gas Company; and the interest that we no longer allocated to TECO Coal following its classification as a discontinued operation. The Florida economy continues to be a good story. Statewide unemployment at the end of the fourth quarter was 5.6%, an improvement of 7/10 from a year ago. At the same time, the state has added more than 233,000 new jobs over the past year, with the largest number of new jobs occurring in business services, trade transport and utilities and leisure and hospitality. The biggest percentage gain occurred again this quarter in the construction sector, which has posted 8% to 10% employment gains every quarter this year. Hillsborough County, Tampa Electric’s primary service territory, also continues to do well. We appear to be back to the pattern that was normal before the economic downturn, with Tampa area unemployment being better than both the state and national level. The employment rate in local area is down to 5.2%, 6/10 below where it was a year ago, and it is not a function of people leaving the workforce, as workforce grew by 0.5% in the same time frame. Over the past year, the Tampa-St. Pete area added more than 14,000 jobs, with the largest gains in business services followed by trade transport and utilities. Supported by the oil and gas industries and the large presence of governmental facilities in the state, the unemployment rate in New Mexico never came close to the levels we saw in Florida, where job losses in the construction and financial services sectors were severe due to the housing market crash. The largest gains in New Mexico’s 2014 job growth of 13,000 came in trade transport and utilities and education and health services. To put some perspective on the job numbers here, it’s interesting to note that the population of New Mexico of about 2.1 million was actually less than the population of the Tampa-St. Pete MSA, which has a population of about 2.8 million. Taxable sale, both in Florida and in Hillsborough County, continue to grow at the strong pace we’ve seen pretty consistently over the last 4 years. We don’t have that statistics here for New Mexico, as we haven’t yet found a ready source of similar information. On the housing front, more than 5,000 single-family building permits were issued in Tampa Electric service territory in 2014, and existing homes continue to sell at a strong pace. The January Case-Shiller report shows that selling prices in the Tampa market increased 6.8% year-over-year, which doesn’t seem to have dampened sales, and the housing inventory remains at a healthy level of 4 months. The New Mexico housing market saw 5,500 building permits issued statewide in 2014, which was an 8% increase over 2013. In Albuquerque, the state’s largest metro area, existing home resales have trended up steadily although slowly since the downturn, and the housing inventory is about 6 months. You can see all of these trends on the graphs in the Appendix. I’m not going to cover all of the details on the New Mexico Gas acquisition, but I do want to point to a few important takeaways. Consistent with the outlook we provided in our third quarter call, the acquisition was accretive to fourth quarter earnings by $0.03; and for the full year, $0.01. You’ll recall that it diluted EPS $0.02 in the third quarter as we had the associated shares outstanding in the entire quarter and 1 month of ownership during the typical seasonal loss period. With our 2015 business plans in place and with the rapid progress implementing our integration plan, we expect the acquisition to be accretive to full year 2015 earnings, and that’s earlier than we originally anticipated. Last October, we announced that we had entered into an agreement to sell TECO Coal to Cambrian Coal Corporation, a subsidiary of Booth Energy, a central Appalachian coal producer with operations in the same general areas as TECO Coal. The sale was contingent upon the purchasers obtaining financing. The coal markets have continued to weaken for several months now. And last week, we amended the agreement to adjust the selling price to reflect market condition and to extend the closing date to March 13. Under the amended agreement, we will receive $80 million at closing and have the opportunity to receive an additional $60 million over the next 5 years if benchmark coal prices reach certain levels. The purchaser launched financing activities last week after the amended agreement was executed. In the third quarter, we classified TECO Coal’s operations as discontinued operation and its assets as assets held for sale. At that time, we recorded noncash impairment charges of $64.8 million after-tax. We recorded additional impairment of $11.6 million in the fourth quarter, and the $16.6 million fourth quarter loss in discontinued operations includes that additional charge and the operating result of TECO Coal. Those operating results were impacted by costs related to preparing the company for the sale, such as severance and other employee termination costs. As we’ve disclosed previously, the actual closing of the sale will trigger an additional liability-related charge, which we estimate at $7 million. Turning to guidance. We expect 2015 earnings from continuing operations in a range of $1.08 to $1.11 excluding non-GAAP charges or gain. This is a tighter range than we’ve provided in the past, and that’s because our business mix is now all regulated utilities. And while weather is always a variable that can affect utility performance, our operating companies have typically been successful responding to weather variation within a reasonably normal range. We expect Tampa Electric to earn in the upper half of its allowed ROE range. That’s driven by customer growth that we expect will be in line with 2014; energy sales to retail customers other than phosphate, off an estimated 1%; higher AFUDC as we enter a peak spending year for the full conversion project; and an additional $7.5 million of higher base rate that became effective November 1 last year. On the expense side, continued investment in facilities to serve customers will drive higher depreciation and interest costs. We’re projecting lower O&M expense, however, in part, as we realize benefits from acquisition-related synergies and also from lower employee-related expenses including pension and retiree medical costs. 2015 changes to the retiree medical program and growth in planned assets are among the factors contributing to the lower expense. And because the acquisition of New Mexico Gas and sale of TECO Coal caused us to remeasure pension expense last year, that remeasurement captured the negative impact of lower discount rates and mortality improvement in 2014. We expect Peoples Gas also to earn above its allowed mid-point return, which is 10 3/4%. Like Tampa Electric, we expect the customer growth trends we saw last year to continue into 2015 and expect continued interest in vehicle fleet conversion to compress natural gas as well. Although current gasoline prices are helpful, the economics are still favorable, and there are environmental benefits that users like to promote. At the end of 2014, Peoples Gas had 31 CNG filling stations on its system, and the annual volume was the equivalent of about 60,000 Florida residential customers. We expect that number to grow again in 2015. And finally, the Peoples Gas expense profile should be similar to what I described for Tampa Electric. 2015 will represent our first full year of ownership of New Mexico Gas Company. And as I said, we expect it to be accretive in that first full year. And I’d like to be clear that there’s no creative math in that statement as I’m taking into account the performance of the regulated company, NMGI interest costs and the shares we issued. We expect customer growth to start the year at about the same levels as 2014 and trend up through the course of the year with growth in therm sales largely in line with customer growth. We expect lower O&M from acquisition synergies, and we also have the REIT credit of $2 million in the first 12 months post-closing and $4 million in each subsequent 12-month period, which have the effect of sharing some of the synergies with customers. Since we only have 4 months of ownership with New Mexico Gas in 2014, the slide shows some information on previous years to provide some full year context. The Form 2 filed with the New Mexico Commission reported New Mexico Gas Company net income of $23.7 million in 2013, which was a strong weather year with heating degree days about 5% above normal; and $18 million in 2012, when heating degree days were well below normal; and higher rates approved by the commission became effective after the January peak load that already occurred. This slide is just to remind us to show the normal seasonal earnings pattern we expect from NMGC. They make their money in the cold weather in the first and fourth quarters, a fairly normal pattern for a gas LDC that’s heavily residential. It actually complements our existing earnings pattern nicely as Tampa Electric’s strongest quarters are typically the second and third quarters with summer air-conditioning load. The segment we refer to us Other net includes interest at the unrelated finance company, interest at NMGI, certain unallocated corporate level expenses and consolidated tax impacts and smaller operating companies, the only one of note being TECO’s pipeline. We anticipate that the net cost in 2015 will be slightly higher than last year because of a full year of interest expense at New Mexico Gas Intermediate. Although we won’t be allocating any interest expense to TECO Coal as we have in the past, the negative impact from that will be offset by the benefit of refinancing a maturing note series that has a coupon of 6.75%. I would summarize our longer-term outlook in this way. Our regulated businesses are investing in infrastructure to serve customers in our growing rate base 5% to 7%. Our target is to deliver ratable earnings growth that’s in line with rate base growth. The challenges in 2016, recognizing that Tampa Electric’s rate base growth is heavily influenced by full conversion projects while an additional $110 million of annual revenue will become effective when that project goes into service at the beginning of ’17, the base rate increase that benefits 2016 is only $5 million. So a key to delivering earnings growth in 2016 will be effective management of cost across the organization. You can see this on the graphic representation of Tampa Electric’s rate base, which shows it stepping up significantly in ’17 when Polk goes in service. The base revenue pattern is very aligned with the rate base growth you see here. The 2013 rate settlement provided additional base revenues of $57.5 million effective November 1, 2013, which coincided with 2014 rate base growth; $7.5 million at November 1, 2014; $5 million at the same date in ’15; and then $110 million when Polk goes in service in ’17. This graph shows average rate base, and it excludes the assets that we earn on separately through the environmental cost recovery clause and the construction work in progress that earns AFUDC above a threshold amount that is included in rate base. As a reference point, at the end of September of ’14, actual average rate base was $4.1 billion, the environmental assets were about $400 million and that clip was about $200 million. Also, with our upcoming Investor communications schedule, we expect to file our 10-K at the end of this month, and we will be at the UBS and Morgan Stanley conferences the following week and at the Barclays conference in Atlanta in the middle of March. And now I will turn it over to the operator to open up the lines for your questions. Question-and-Answer Session Operator [Operator Instructions] And your first question comes from the line of Ali Agha with SunTrust. Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division A couple of questions. One is, you recently raised your dividend by 2.3%. And I wanted to just get a sense of what is the philosophy on the dividend and growth going forward. I know we’ve talked previously about the NOLs, but they’ll go away in a few years. So can you just remind us again how you’re looking at the dividend? And ultimately what’s the payout ratio, and when do you expect to be in that payout ratio? John B. Ramil This is John Ramil, and I appreciate you asking that question. When we look at our payout ratio versus our guidance for next year, it’s a little bit above 80% as opposed to our kind of normalized target of 60% to 70%. And we expect over time with the 5% to 7% earnings per share growth, coupled with a modest dividend growth that we will work ourselves back into that more normalized range as we work ourselves out of the NOL position, and that’s expected to be in about 2019. Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division Understood. Great effort. Second question, John, as you, I think, pointed out on the coal sale, the buyer, I guess, started their financing plans last week as well. Any concern at all about their ability to raise the financing? I know that’s the contingency left to close this. John B. Ramil Well, you’re right, they did kick off their financing on Friday of last week, and we’ve been working very closely with them on where they are in their financing, what the markets are doing and in working with them with the objective of getting this deal closed and moving the coal business out of our portfolio. That’s why we agreed to an amended deal to really strengthen the ability for them to get the financing for this transaction to close. Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division Okay, and you’re very confident that, that financing will close. I mean, there’s no — I mean, from your perspective as the seller, any concerns? John B. Ramil All the indications we have and the advice that we’re getting is where we’re at in pricing and where the markets are expected to be, that transaction can close. Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division And my last question. On New Mexico, as we think about calendar 2015, you were talking about your expectations for Tampa Electrics on the ROE and Peoples Gas on the ROE. How should we think about New Mexico’s on the ROE? I believe their authorize is 10%, if memory serves me right. So how should we think about what — where — roughly where they should be earning in the order of magnitude? John B. Ramil That’s correct. And with all of our people doing very, very good cost control work, as you can see, that is continued in 2014. And with the synergies that all of our utilities are seeing from the integration, it’s helping improve all the ROEs. And New Mexico Gas has been low — earning closer to 9% ROE, and we expect to keep moving that up towards that 10%. Ali Agha – SunTrust Robinson Humphrey, Inc., Research Division Okay. Somewhere between 9% and 10% should be the expectation for ’15? John B. Ramil That’s correct. Operator And your next question comes from the line of Paul Zimbardo with UBS. Paul Zimbardo – UBS Investment Bank, Research Division I just had a question about what your thoughts are on possibility of rate base gas and solar opportunities. nexAir has talked about it on some of the recent calls. And just how do you think about that going forward for you? John B. Ramil Well, we’re watching what’s happening with Florida Power and Light very closely. They reached — got some approvals along the way, and there’s still more things to happen there. And with the proper regulatory treatment, it’s a reasonable investment for utilities to make. So we’re keeping our eyes closely on it. We’re also very interested in large-scale solar. We expect that over time, that’s going to make more and more sense. We think that the commission is receptive to the right projects. In fact, last year, late in the year, I think it was during the fourth quarter, we announced the plans to install a larger scale solar facility at the Tampa International Airport. So we’re moving in that direction. We looked ahead to our next capacity need after the Polk expansion, being in about 2020, and while we have that kind of penciled in as a combustion turbine at this point, we think it’s likely that through some combination of various size solar projects, we’d see that CT replaced with solar capacity. And we think that the commission, the economics and the realities of additional environmental requirements will make that good decision. Paul Zimbardo – UBS Investment Bank, Research Division Okay, so no real plans to do anything in the next 3, 4 years, take advantage of ITC or anything like that? John B. Ramil Well, I just mentioned we announced a project in the Tampa International Airport, and that will go into service in that time period. But beyond that, I mean, our immediate need is being met by the Polk expansion, which is driving our growth through 2016 — I’m sorry, through 2017. Paul Zimbardo – UBS Investment Bank, Research Division Okay, got it. And then one other last question. On the current refinancing of the 6.75% notes, are you able to quantify the magnitude if you plan on letting any of that roll off? Or will it just be a straight refinancing? Sandra W. Callahan We will likely refinance the whole maturing amount. Operator And your next question comes from the line of Paul Ridzon with KeyBanc. Paul T. Ridzon – KeyBanc Capital Markets Inc., Research Division If parent companies in Cambrian have issues, kind of can you talk about Plan B? John B. Ramil Sure. We’ve been working with them for quite a while. We have had other expressions of interest but feel that they are the most likely candidate to get this transaction done. If, for some reason, that doesn’t happen, we will look to others as possible buyers, and we’ll also look at other ways of selling the asset. Paul T. Ridzon – KeyBanc Capital Markets Inc., Research Division And given the lower economics, does that impact equity needs at all? John B. Ramil No. Paul T. Ridzon – KeyBanc Capital Markets Inc., Research Division Okay. And then lastly, can you kind of give the next couple of years’ CapEx schedule? Sandra W. Callahan Well, we will be filing a revised capital spending forecast in our 10-K. Paul T. Ridzon – KeyBanc Capital Markets Inc., Research Division At the end of this month? Sandra W. Callahan At the end of this month, right. Operator And your next question comes from the line of Andy Bischof with MorningStar. Andrew Bischof – Morningstar Inc., Research Division LI know the total potential future consideration came down as part of the amended coal deal. But can you speak to whether or not the benchmark pricing come down at all? John B. Ramil The future consideration actually went up to $60 million and the benchmark number stayed the same. Operator And your next question comes from the line of Scott Senchak with Cannon. Scott Senchak Just you have some debt maturities also in ’16 and ’17. I was just wondering what your plans were there. John B. Ramil Scott, would you repeat that? I’m not sure exactly what you asked. Scott Senchak Sorry, you have some debt maturities in 2016 and 2017. I was just wondering what your plans are for those as well. Should we expect a straight refinancing there or what the plan is there? Sandra W. Callahan For the most part, Scott, probably refinancing, but we may retire some portion of those maturities in those years. Operator [Operator Instructions] At this time, there are no further questions. I would like to turn the call back over to Mr. Mark Kane. Mark M. Kane Thank you, Keisha. Thank you, all, for joining us today. We know there are other activities occurring in this morning, so we appreciate you taking your time to join us on our call. And we look forward to seeing you at various Investor conferences in the future. This concludes our call. Thank you. Operator Thank you, all, for your time and participation. This does conclude today’s conference call. You may now disconnect.

A More Tempered Global Equity Fund

By Patricia Oey Low-volatility strategies, such as the iShares minimum volatility family of exchange-traded funds, can be attractive options for long-term investors. This is because these ETFs’ underlying MSCI indexes generally exhibit less-dramatic declines in bear markets . Over the long term, these muted drawdowns explain much of the strategy’s outperformance versus its cap-weighted benchmark. iShares MSCI All Country World Minimum Volatility (NYSEARCA: ACWV ) tracks an index that is designed to be less volatile than its market-cap-weighted parent index–the MSCI All Country World Index (MSCI ACWI). Low-volatility strategies seek to exploit the observed phenomenon that portfolios with smaller price fluctuations tend to outperform portfolios with larger price fluctuations over the long term. This strategy has had a good track record–as measured by the back-tested performance of this fund’s benchmark index (the index’s live performance commenced in November 2009). Over the trailing 15 and 10 years through Dec. 31, 2014, this fund’s underlying index beat the cap-weighted MSCI ACWI by 393 and 202 basis points annualized, respectively. The risk-adjusted returns were also relatively strong, with 15-year Sortino ratios of 0.73 for the minimum-volatility index and 0.22 for the cap-weighted index. However, low-volatility strategies can underperform for long periods of time and tend to lag in bull markets. This fund is suitable for use as a core holding for long-term investors. Typically, global-equity funds are more volatile than U.S. equity funds, as the former have exposure to both international equities and the associated foreign currency fluctuations. But because global equities are a heterogeneous asset class, there is greater diversity (as evidenced by lower correlations) among its constituents, which allows for greater reduction in overall volatility in a fund that employs a minimum-variance strategy such as ACWV. In fact, the trailing five-year standard deviation of returns for this fund’s index of 9% was significantly lower than the S&P 500’s 13% during that same span. Part of this is due to the benchmark’s lower drawdowns during bear markets. For example, in 2008, when the MSCI ACWI fell 42%, this fund’s benchmark declined 25%. This fund does not hedge its currency exposure, so its returns reflect both asset-price changes and changes in exchange rates between the U.S. dollar and other currencies. In the 10-year period through December 2012, a rising euro, followed by a rising yen (against the U.S. dollar), helped boost the performance of this fund. However, more recently, the rising dollar has hurt the fund’s performance. Fundamental View Historically, low-volatility stocks have outperformed high-volatility stocks over the long term. This “volatility anomaly” was first discovered in 1968 by Bob Haugen, who theorized that behavioral factors were behind this phenomenon. More specifically, investors tend to chase risky stocks, expecting these companies to deliver higher returns. This drives up stock prices of riskier names, which ultimately results in weaker future returns, relative to less-volatile names. Generally, this fund had been heavy in less-volatile sectors including consumer staples, health care, telecoms, and utilities, and light in cyclical sectors including financials, technology, energy, and materials, relative to its parent index (MSCI ACWI). In 2013, the fund’s greater exposure to less-volatile names in the United States and Japan weighed on its performance (relative to the MSCI ACWI), as higher-beta names outperformed in those markets. However, in 2014, the fund’s underweighting in the energy sector boosted this fund’s performance (relative to MSCI ACWI). At this time, dividend-oriented sectors such as consumer staples and utilities have been bid up in the recent low-rate environment, and sectors such as materials and energy are trading at low valuations. This fund’s tilt toward more-expensive sectors and tilt away from cheaper sectors may weigh on future performance. About 50% of this fund’s assets are invested in U.S. equities. As of the first quarter of 2015, the U.S. economy appears to be on stable footing. However, now that the U.S. Federal Reserve’s quantitative-easing program has ended, there is uncertainty on how monetary policy will be managed and how it might ultimately affect asset prices–especially considering that valuations across most major asset classes appear to be somewhat stretched. This fund’s second-largest country allocation is Japan, at 12%. After two “lost decades,” Japan’s equity markets responded very enthusiastically to Prime Minister Shinzo Abe’s programs to jump-start the Japanese economy. At the start of 2013, Japan’s Central Bank unleashed an aggressive monetary easing program. This move provided the foundation for improving macroeconomic fundamentals and corporate earnings growth. Japanese equities may also benefit as Japan’s $1.2 trillion public pension raises allocations in domestic equities and away from low-yielding government bonds. However, any sustainable growth in Japan will require difficult-to-implement structural reforms to address Japan’s inefficient labor market and protected private sector. In addition, Japan’s aging population and massive 200% debt/gross domestic product ratio are two issues that likely will weigh on Japan’s growth in the years to come. European equities comprise 10% of this fund’s portfolio. Many European large caps are high-quality, multinational corporations that have benefited from improving productivity, cheap financing, and exposure to faster-growing emerging markets during the past few years. Most of these firms are in good financial shape. This fund’s largest European country allocations are Switzerland and the United Kingdom, and it has an underweighting (relative to the cap-weighted benchmark) in eurozone countries, such as France and Germany. Portfolio Construction This fund employs full replication to track the MSCI ACWI Minimum Volatility Index, which attempts to create a minimum-variance (or lowest-volatility) portfolio of 350 holdings selected from its parent index, MSCI All Country World Index. It does this using an estimated security covariance matrix (the Barra Global Equity Model) and a number of constraints to limit turnover, ensure investability, and maintain sector and country diversification. This index methodology is somewhat of a black box, as data are not available regarding the estimated risk inputs used for the covariance matrix. The index (and fund) is rebalanced twice a year in May and November. ACWV’s portfolio represents about 20% of its parent index, which includes about 2,400 securities. During the past decade, this minimum-volatility index had a correlation of 0.92 to its parent index. But during the past three years, this correlation was lower, at 0.79. This index was launched in November 2009, so data prior to the initial calculation date reflect hypothetical historical performance. Fees This fund charges an annual expense ratio of 0.20%, which is composed of a management fee of 0.33% and a fee waiver of 0.13%. According to iShares, the fee waiver may be reduced or discontinued at any time without notice. During the past three years, the fund outperformed its benchmark by 16 basis points annualized. This is partly due to the fact that the fund’s benchmark incorporates aggressive foreign tax withholding assumptions. In practice, the fund has had lower foreign tax withholding relative to the estimates incorporated in its benchmark. Dividends are paid out quarterly, and in 2013 and 2012, 86% and 71% of this fund’s dividends were classified as qualified by the Internal Revenue Service, respectively (dividends from companies in certain countries are not considered qualified). Investors should note that some of the dividends paid by stocks in the fund are subject to foreign tax withholding. Investors can claim their portion of the withheld taxes as a tax credit, but only if they hold this fund in a taxable account. Alternatives One similar option is Vanguard Global Minimum Volatility (MUTF: VMNVX ) . Similar to the iShares fund, this Vanguard fund employs quant models to construct a low-volatility portfolio. Key differences are: The Vanguard fund hedges out foreign-currency exposure and has a mid-cap tilt, whereas the iShares fund does not hedge out foreign-currency exposure and has a large-cap tilt. This Vanguard fund is relatively new; its inception was in December 2013. The Admiral share class carries an annual expense ratio of 0.20%. IShares has a suite of low-volatility strategies that cover the different segments of the global equity universe. These ETFs include iShares MSCI USA Minimum Volatility (NYSEARCA: USMV ) , iShares MSCI Emerging Markets Minimum Volatility (NYSEARCA: EEMV ) , iShares MSCI EAFE Minimum Volatility (NYSEARCA: EFAV ) , iShares MSCI Japan Minimum Volatility (NYSEARCA: JPMV ) , iShares MSCI Asia ex Japan Minimum Volatility (NYSEARCA: AXJV ) , and iShares MSCI Europe Minimum Volatility (NYSEARCA: EUMV ) . A solid core allocation option is Vanguard Total World Stock ETF (NYSEARCA: VT ) . This fund tracks the FTSE Global All Cap Index, which seeks to cover 98% of the world’s total investable stock market capitalization and includes approximately 7,500 securities. It has an expense ratio of 0.18%. Disclosure: Morningstar, Inc. licenses its indexes to institutions for a variety of reasons, including the creation of investment products and the benchmarking of existing products. When licensing indexes for the creation or benchmarking of investment products, Morningstar receives fees that are mainly based on fund assets under management. As of Sept. 30, 2012, AlphaPro Management, BlackRock Asset Management, First Asset, First Trust, Invesco, Merrill Lynch, Northern Trust, Nuveen, and Van Eck license one or more Morningstar indexes for this purpose. These investment products are not sponsored, issued, marketed, or sold by Morningstar. Morningstar does not make any representation regarding the advisability of investing in any investment product based on or benchmarked against a Morningstar index.

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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