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California Water Service’s (CWT) CEO Martin Kropelnicki on Q1 2016 Results – Earnings Call Transcript

California Water Service Group (NYSE: CWT ) Q1 2016 Results Earnings Conference Call April 08, 2016, 11:00 am ET Executives Dave Healey – Vice President, Corporate Controller Martin Kropelnicki – President, Chief Executive Officer, Director Thomas Smegal – Chief Financial Officer, Vice President, Treasurer Analysts Jonathan Reeder – Wells Fargo Operator Good morning, ladies and gentlemen. Welcome to the California Water Service Group first quarter earnings results teleconference. Today’s conference is being recorded. I would now like to turn the meeting over to Dave Healey. Please go ahead, sir. Dave Healey Thank you, Wes. Welcome everyone to the first quarter earnings results call for California Water Service Group. With me today is Martin Kropelnicki, our President and CEO and Thomas Smegal, our Vice President, Chief Financial Officer and Treasurer. A replay of today’s proceedings will be available beginning today, February 28, 2016 through April 28, 2016 at 1-888-203-1112 or at 1-719-457-0820 with a replay pass code of 9747630. As a reminder, before we begin the company has developed a slide deck to accompany the earnings call this quarter. The slide deck was furnished with an 8-K this morning and is also available at the company’s website at www.calwatergroup.com/docs/earningsslidesmarch2016.pdf Before looking at this quarter’s results, we would like to take a few moments to cover forward-looking statements. During the course of this call, the company may make certain forward-looking statements. Because these statements deal with future events, they are subject to various risks and uncertainties and actual results could differ materially from the company’s current expectations. Because of this, the company strongly advises all current shareholders as well as interested parties to carefully read and understand the company’s disclosures on risks and uncertainties found in our Form 10-Q and other reports filed from time to time with the Securities and Exchange Commission. Now let’s look at the first quarter 2016 results. I am going to pass it over Tom to begin. Thomas Smegal Thanks Dave. And just as an overview of what we are going to discuss today, we will go over our financial results, some of the highlights and changes there, talk about the drought in California and talk about our rate cases, give you an update on our CapEx program and balance in our WRAM decoupling mechanism, bridge the earnings and Marty will have some closing comments as well. So turning to financial results. Our operating revenue for the quarter was essentially flat compared to the operating revenue in the first quarter of 2015. A couple of competing things there related to water production costs. Sales are down, but the price for our purchase water is up. Those offset each other. Operating expenses or purchase water costs are down because of the volumes and that’s offset as we will discuss it in a moment by maintenance costs and drought related activity costs. Other highlights on slide five of our deck are that our interest cost is up. That is due to new long-term debt, both in October and in March, October of 2015 and March of 2016. So our net income is down $2.4 million and our EPS is down about $0.05 from the year ago period. So flipping to slide six of our deck on the financial highlights. We had incremental drought expenses of $2 million in the quarter. That is a little higher than our run rate for the previous six months, this last six months of last year and has to do with communications that we made to our customers about with the new drought tariffs and changes to the drought regime in 2016. So that is a bit higher than it’s been. Once again the drought costs are subject of an approved memorandum account of California Public Utilities Commission. That means that we record those costs and we are going to ask for recovery of those costs that has to go through a reasonableness review and we will expect a future increase in our revenue to cover that. But those are being passed through to expense right now. Our maintenance expenses were $1.6 million higher during the quarter and that has to do with again the drought. We believe this is a very similar run rate on maintenance expenses that we have had for the last two quarters. We believe a lot of that has to do with fixing leaks when they occur despite the magnitude of the leak. In a normal time, we would have prioritized leaks and addressed the much smaller leaks in due the time when we had a spare moment, Now, we are trying to fix every leak every day and that is driving up our cost for maintenance. And as I mentioned before, the interest expense due to the long term debt did increase our expense by $800,000. Two big highlights for us for the quarter. Our company and developer funded capital investments were $55.6 million. That is really on target for our $180 million to $210 million CapEx spend for the year. So we are very excited about that. That’s probably the highest amount of CapEx in the first quarter in the company’s history. The second really good news item is that our customer receivable for the WRAM decoupling mechanism declined to $33.6 million. That was in part due to $11 million of drought surcharges and the effect of new rates that were put in 2016 that lowered the expected sales and therefore bring us closer to recorded and adopted sales. And finally as we noted that we did complete our financing, our long term debt financing with $50 million and that was in March, previously announced. Now I am going to turn it over to Marty for some updates on the drought. Martin Kropelnicki Thanks Tom. Good morning everyone. I want to give you a quick update on the drought situation in the State of California, our performance and where we are in terms of our savings with our customers versus the emergency declared by the Governor last year in the State of California. First and foremost, we ended the quarter. So the savings for March, we were at 27.9%. So we are continuing well above the state 25% mandate. A couple of interesting stats to a share with everyone. If you look at the estimated savings for the state from June 1, 2015 through the end of February, the state saved 1.19 million acre feet of water through the conservation efforts that were declared in emergency declaration. During that period, Cal Water customers saved 74,000 acre feet, which is about 6.2% of the total savings for the State of California. So I think when you look at how robust our drought program has been and how well our customers have done in terms of hitting their targets, we have been very pleased with our contributions to the savings that they have put with State of California. As we put in the deck, Northern California, we are coming into the spring month now. Northern California had above normal rainfall and snowfall levels than Southern California. It was different. They were lower than normal. So just to share some numbers with everyone that I think are going to be very important, the snowpack reading that took place on April 1, which is a very important in the State of California, statewide the snowpack levels were at 85% of normal. But when you dissect North versus South, you will start to see how the picture changes a little bit. In Northern California, we were above 95% of normal, but when you go down to the snowpack range in Southern California, they are only 71% of normal. So again, most the snow and rain happened in northern parts of the state. Likewise, when you look at reservoir levels throughout the state, when you look at Northern California, most of our reservoirs are at 100% of capacity and 100% of their historical averages for this time of year. When you move to Central California, most of the reservoirs are between 40% and 80% of their historical averages, but only at about 40% to 50% of their total capacity. And then when you move to the reservoirs in Southern California, they are between 40% and 80% of normal in terms of the historical averages, but well above 50% of capacity. So despite the strong rain and snowpack in the North, you can still see why the drought has been extended through October 31 of this year. Having said that, clearly we have more water this year and as we have in the deck, the State Water Project bumped up their allocation to 60%. It’s the highest it’s been in five years. So that’s good news. That allows us to move more water from Northern California to Southern California. Likewise with the Federal Water Project, we have seen an increase in allocations as well. In 2015, the allocation for urban areas was 25% on the federal project, that’s been bumped up to 55%. And on the agriculture front, the allocation from the federal project was zero in 2015 and that’s been bumped up to 5% for 2016. So again, well, conditions have improved. They vary dramatically depending on where you are through the state. Northern California is in fairly good shape. But clearly Southern California is below average. What will happen next? The State Water Resources Control Board, we are expecting them to issue updated draft regulations any time during the next 10 days. They have a meeting scheduled to approve any changes on May 18. And then those changes will go into effect on 6/1. So in terms of where we are, I fully expect and this my personal opinion, that you will see some easing of the drought restrictions but clearly we are not going to see them go away. And again, you can just look at that the numbers I gave you, if you run them down, Northern California versus Southern California, we are still not where we need to be and frankly we are far from it, even with the strong rains in the North. So watch those new rates to come out shortly and we will be communicating on the second quarter earnings call what the changes are to the drought policies for the State of California and the impact on Cal Water. Likewise, one of the things we put on slide seven is that we have implemented in our drought program, I call it a dead band, the drought people call it a courtesy tier, given the fact that 80% of our customers are coming in at or below their conservation targets. Basically a band around the tear-off before they get a surcharge. So if they go one unit over their authorized amount, they are not hit with a penalty. So it gives customers a little bit more breathing room. We expect that will reduce the number of calls to the drought call center and ease some of the backlog that we have seen on applications for exceptions to their water allocation budget process. Tom, back to you for an update on the regulatory mechanisms. Thomas Smegal Yes. Just a reminder to everyone of the regulatory mechanisms in California that help us through the drought. Obviously, we has been decoupled since 2008 with WRAM and MCBA mechanisms and again what that does is it keep our revenue normalized even if the sales are declining. And then the drought costs, as I mentioned before, the $0.02 EPS impact in the quarter or the $2 million, we do expect to request approval for last year’s expenses in the second quarter. If you will remember, the expenses there were about $4.4 million for 2015. We are preparing that filing for the Commission and expect to file that within the next 90 days and that will go to the review process. The expenses for 2016 will be on our review schedule later on. Our customer surcharges, as I mentioned, it really positively impacted our WRAM balances. $11.4 million of drought surcharges recorded in the quarter and the WRAM balance again declining $6.9 million in the quarter and year-to-date. And the other thing that I have been mentioning on these calls is that we did have a mechanism called the sales reconciliation mechanism which allowed us to change or rates for customers in 2016 with a lower expectation of sales, so that when those sales do come in lower due to the drought, the potential WRAM balance is much smaller and so that improves for cash collections. And Marty, I am going to turn it back to you for a rate case update. Martin Kropelnicki Great. On slide nine, that’s the recap. I think you maybe have seen this before of what our rate case was for July 1 last year that we filed, July 1, 2015 that was filed with the California Public Utilities Commission. I am not going to go through the numbers here rather than on the last bullet point, we are about nine months through the 18 month process. And if you turn to the next page, on page 10, we will give you more of an update. So we did receive the Advocates’ report or the ORA report. Today, close of business today, we will be filing our rebuttal testimony. To give an idea of how many people have been working on this, we have got about 115 people throughout our company working on rebuttal and support for rebuttal testimony. So we have about 2,000 pages of testimony that will get filed at close of business today. Likewise, during the first quarter we have started our public participation hearing meetings. We will our sixth public participation hearing meetings tonight and those are progressing as scheduled. And we have our interveners lined up. In total, there are 17 intervening parties in the rate case. Most of what our cities and counties and we are going to the process of starting to meet with them. So in terms of next steps for the rate case, as we file the rebuttal testimony and then we will start settlement negotiations on or around approximately May 9. So things are right on track as of right now, but now is where the rubber meets the road, which is a settlement discussions or if we decide to litigate. And so we will have a much better sense of where we are with the Q2 call at the end of July and we will provide a detailed update then. If you go to page 11, as Tom said, this is the best first quarter in terms of CapEx spend. We spent 27% of our budget. If you remember our range was between $180 million and $210 million. I think it’s noteworthy that it is the highest number we have recorded in the first quarter in terms of capital investment. It’s also noteworthy that we accomplished this with so many people working on the general rate case rebuttal testimony and a lot of support has to come from engineering on the capital program for that rebuttal testimony. So overall very happy with the start of the year in terms of our capital program and the results and the productivity we are getting out of our engineering departments which you may recall, we reorganized in the fourth quarter of last year. So overall off to a very good start on our CapEx and look forward to seeing how that number progresses throughout the year, Tom? Thomas Smegal Sure. The next slide is a graphical representation of our WRAM and MCBA net balances. These are receivable balances from customers over the last five-and-a-half years. And what you will see here and what’s notable is that we have really made an impact with the drought surcharges on that WRAM balance. We have as low a balance as we have had since the very beginning of 2011 and that was really in a period back then when things were rising and things were off-kilter. We are getting back to a spot where we expect this to continue to decline. So really happy about that receivable balance. On the next page, just an earnings bridge from 2015 to 2016 for the first quarter and you will see there that the big impacts are obviously, as we talked about, the drought expenses and the increased maintenance expense. And all other items that impacted us about $0.01 and that includes the interest and other cost changes on us. And so that is it for the deck. I do want to pass to Marty for some closing comments. Martin Kropelnicki Great. Thanks Tom. Well, it’s nice to have Q1 behind us. For those of you who have been with us for a while, Q1 is always our leanest quarter of the year and that is especially true, the third year of the rate case cycle which is where we are in right now. It’s the year we have the least amount of rate relief and we start to see regulatory lag in certain costs. While we have a number of balancing accounts that cover major costs, things like labor, chemicals and filters, some of the operating lines are affected by a lack of charges that creep in during the third year. So nice to have the third year behind us. In terms of what the company is focused on during the second quarter obviously, as I mentioned earlier, the rebuttal testimony is key. We expect to file that today, close of business today and then start settlement discussions approximately a week, week-and-a-half later. The second thing and Tom mentioned this earlier as well, is filing for the recovery of drought cost from 2015. So the 2015 costs will be filed on a stand-alone basis and then 2016 cost will be recorded to the memorandum account for this year and then what happens with the drought. And so we will know a lot more about the drought. I fully expect some type of restrictions to continue throughout the year, but what that will be, we don’t know as of now and we expect to find that out in the next two weeks. And like I said, we will be communicating that once we know what those restrictions are. So overall kind of the quarter was what we thought it would be. If you back out the drought expenses, we were tracking right to where our internal budgets were. And then we will be focused on the drought and any change to be made in our capital spending for 2016 in the rate case. So Tom. Thomas Smegal Thanks. Wes, we are ready to take any questions that people have. Question-and-Answer Session Operator [Operator Instructions]. We will go first to Jonathan Reeder at Wells Fargo. Jonathan Reeder Hi. Good morning, Marty and Tom. Thanks again for slide deck. That’s helpful to follow along. First question, so including the drought costs, earnings were essentially flat in Q1. Were there any other items that you would single out as nonrecurring? Thomas Smegal I don’t think so. You can always pick your expenses apart and say, well that legal bill or that consultant bill is in this quarter and not in that quarter or anything like that. I don’t see that there is anything significant in any of those variations. Just normal stuff. Jonathan Reeder So were there any items in Q1 that were not in line with your expectations or plan for 2016? Or did the quarter, for the most part, go the way you were anticipating? Thomas Smegal I think it did go the way we were anticipating. We do have an internal budget obviously and we are tracking pretty close to that. I think just the drought costs are the big item there and the maintenance costs that are probably related to the drought as well. Martin Kropelnicki And one thing I would highlight on the drought costs, we did have a step-up in advertising in terms of related to the drought. And that’s because as we go into the winter months, it’s a lot harder to hit your conservation targets. In the spring and summer months, people have their lawns, you start watering, outdoor watering and that’s where we get a lot of the savings from during the summer months and fall months. But as you go into winter, people turn off their water. So we stepped up our advertising campaigns in the districts that weren’t hitting their targets. Thomas Smegal And Jonathan and everybody, I think the other thing to note is, with the uncertainty related to how much drought restriction we are going to have this year, there is a potential that the drought costs will start to come down a little bit over the second quarter, third and fourth quarter of the year. The $2 million, I wouldn’t characterize as a run rate every quarter for the company going forward. We have seen a slight decline in the number of calls to our drought call center. And so we are going to manage the staffing on the call center. We are going to be managing the staffing related to the outreach customer or direct outreach. And so if you see the state coming in with a major reduction in the drought requirements, we will also probably see a reduction in our costs on a go forward basis. Jonathan Reeder Okay. Do you think, is the state, would they distinguish between the North and the South in terms of restrictions? Or is it just going to be a blanket thing? Thomas Smegal We participated in a couple of calls talking about different ideas. One idea was that you basically put it at a groundwater adjudication level or at a regional level and allow each region to make the appropriate changes based on their water supply situation. But as you know, the groundwater adjudication bill which was signed a year-and-a-half ago, that’s not fully implemented yet. So we are not sure that’s probably going to work. So we are not sure of what they are going to do. But I think when you look at the numbers, if you look at the snowpack and reservoir levels, you get the clear sense of Northern California is great shape, Southern California is still really in a danger zone. And while we have water to move from the North to the South, on average the snowpack was not at average. It was still below average. And so this was supposed to be a big El Niño year. So I think there is a number of factors they have to work through and we just don’t have clarity we will get the orders from them here, like I said, expected within the next two weeks. Then we will know what to do once we see that. But I still think you will have drought restrictions statewide at some level. Jonathan Reeder Sure. And then did you specify when you are going to file for the 2015 drought cost recovery? Thomas Smegal They are working on that now. We think we will have it filed some time here during the second quarter and it has been a busy, busy, busy time for the rates team. There is core team of about 15 employees who work on the staff, the rate case is actually for the four states. So between the GRC and preparing to file for recovery of the drought costs, everyone has been really busy, but performing very well. Very happy with how everyone is performing. They were on schedule. So you will see it filed here in the second quarter, I believe. Jonathan Reeder And then potential to pickup would be by Q3? It’s pretty quick turnaround? Martin Kropelnicki Yes. It’s an advice letter process. So presuming that the Commission determines things are reasonable, I think it could move within 90 days of filing. That would be a best guess. But with the Commission, you can never tell. Jonathan Reeder Sure. Martin Kropelnicki It could get held up. Jonathan Reeder Okay. Any impact from unbilled revenues in Q1, like we have seen in the past few quarters? Thomas Smegal There was a slight positive this quarter when you get out the Q and look at that, it’s not a negative for the quarter this time. But remember that the big negative that we had in 2015 was the second quarter. And so we will be watching carefully to see how we are different in the second quarter from the second quarter of 2015. Jonathan Reeder Okay. And then any discussion for extending the water GRC to cover for you [indiscernible]? I know that some of that’s been kicked around a little on the electric side? Martin Kropelnicki I know that there has been a lot of interest in the water rate case plan among the different parties, the water companies and ORA have talked about this periodically over the years. But there is no formal effort to change it at this point of water side. And if we were going to change it, we will probably see some other things. I think some of the companies and ORA are sick of having the cost to capital as a separate item. And so if you change the schedule, you might also change that, embed that back into the rate case. So those changes, I don’t anticipate but we will follow the energy industry and see what changes there. Jonathan Reeder Okay. And then last question and I will hop off. Can you quickly sum ORA’s testimony in terms of the CapEx budget and the revenue increases and just how that compares to your request? I know you are filing a rebuttal. Thomas Smegal Yes. The easiest sum is, no. NO. Obviously in our rate case, we made a case for a major expansion of our CapEx and we think it’s with very good justification. We went into great amount of detail as far as we have talked to this community about the need for additional main replacements and how we have been following behind our main replacement program. The attitude of the Ratepayer Advocates seems to have been in opposition to that expansion. As I think Marty, did you mention the number of pages of rebuttal testimony? I think it was about 1,000 pages. Martin Kropelnicki 2,000 pages. Thomas Smegal 2,000 pages of rebuttal testimony. So we are going in fighting. It’s not unusual as a former regulatory person all the way down from the regulatory VP to a regulatory analyst, the worst day of my year has always the day I get the ORA or DRA report and then we just move on from there. Because remember that they are not the Commission. They are an advocate and they are taking a position and often it’s a very short term position as far as the immediate impact and looking at the long term effects on the system. So we have a lot of confidence that our arguments are good and that we will be able to reach a settlement or if we don’t get to settlement, that we are going to able to go through and litigate and have a favorable outcome. Jonathan Reeder I was going to say, based on those comments, if was a different kind of mindset between the short-term and long-term nature of the two sides. It seems like reaching a settlement could be a little more challenging this time around. Thomas Smegal I don’t mean to be too pessimistic about the settlement possibilities. I know that we have a very good relationship with the staff of ORA in terms of a working understanding of passing data back and forth. There is no intent on either side to hide information or couch arguments in terms of really expressed terms. So I think that we are expecting to have settlement. And I believe that ORA is expecting to have settlement. And that’s always encouraging. If we were to know, for instance, that they have no intention of settling and wanted to litigate everything, then I would be feeling a little bit differently. But I know for a fact that we have been trying to negotiate which subjects get settled at which time. And so there is a high likelihood that we will have a productive settlement discussion. Whether that leads to a full settlement or not, I don’t know. Martin Kropelnicki Yes. I think Jonathon, we have spent a lot of time preparing this rate case. And I think Tom and I have really been focused on getting the company to focus on the long-term planning around capital. So we have got a lot of people to work on the rate case. We put our best people on the rate case, including Tom is doing a big piece and I got a piece of it. We have three or four officers dedicated to working on it. So I think we are going in in a very good position and we just have to see where the process takes us. I think it’s fair to say, this is probably the best job we have done on our justifications in terms of making sure that we are well rounded, well thought out, well backed up with data and third-party data to validate the company’s positions. So their job is to say no and our job is to convince them why we need it and have good reasons and explanations for that. And that’s the next step of the process here. Jonathan Reeder Okay. Thanks so much for the insight and good luck over the next few months. It sounds like it’s going to be a pretty busy time. Thomas Smegal All right. Martin Kropelnicki Thanks Jonathon. Operator [Operator Instructions]. And we have no further phone questions at this time. Martin Kropelnicki Okay, Wes. Well, just to wrap up, I want to thank everybody for their continued interest in California Water Service Group. We look forward to giving you updates on all these subjects with our second quarter call. And have a good day, everybody. A -Thomas Smegal Thank you. Operator That concludes today’s conference. Thank you for your participation. 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. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. 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How Scared Should We Be About Future Returns?

McKinsey had a really nice piece this week on the future of financial market returns. The basic conclusion – lower your expectations and hunker down for some lean years in the financial markets. McKinsey says that equities have benefited from unusually favorable conditions in the last 30 years such as low valuations, falling inflation, falling interest rates, strong demographic growth, high productivity gains and strong corporate profits. Specifically, they say: ” Despite repeated market turbulence, real total returns for equities investors between 1985 and 2014 averaged 7.9 percent in both the United States and Western Europe. These were 140 and 300 basis points (1.4 and 3.0 percentage points), respectively, above the 100-year average. Real bond returns in the same period averaged 5.0 percent in the United States, 330 basis points above the 100-year average, and 5.9 percent in Europe, 420 basis points above the average .” That’s a nice clean view of the future relative to long-term returns. I think McKinsey is dead right – the last 30 years were unusual and something closer to the 100-year average is probably reasonable. I’ve stated in the past that the math here isn’t terribly controversial (or shouldn’t be). If a 50/50 stock/bond portfolio has generated 30-year average returns of 9.5%, then we should expect the future returns to be lower or more volatile. In other words, you can, with near certainty, expect that the high risk adjusted returns of the last 30 years are gone. Why is this a certainty? Well, it’s a simple function of the current interest rate environment. Because the post-1980 era involved a huge bond bull market, the risk adjusted returns of a balanced portfolio were unusually high. For instance, from 1985-2015 a 50/50 stock/bond portfolio posted returns of about 9.5% with a Sharpe ratio of 0.7 and a Sortino ratio of 1.5. That’s because the bond piece, which is inherently more stable, generated average annual returns of 7% with a Sharpe ratio of 0.76 and an eye popping Sortino ratio of 2.12, while the stock piece generated annual returns of 12.5% with a Sharpe ratio of 0.5 and a Sortino of just 0.92. In other words, bond investors have done extraordinarily well over the last 30 years thanks to the favorable tailwind of falling inflation and falling interest rates. And those outsized bond returns had a hugely positive impact on diversified investors. We also know that the best predictor of future bond returns is current yields so, do the math on the 1985 starting overnight interest rate of 7.5% versus today’s rates of 0%. A bond aggregate held for the next 10 years is unlikely to outpace the current yield of 2.25% by much. So, we know for a fact that the bond piece won’t generate anything close to the types of returns it did in the last 30 years. But there’s also good historical precedent here. In the 1940s, rates were as low as they are today. So, how did the bond market do? It did okay, but it certainly wasn’t anything like the post-1980 period. From 1940-1980, bonds posted annual returns of 2.75%, but were very stable (much more stable than is commonly believed in a rising interest rate environment). The stock piece, however, performed very similarly to the post-1980 period, with rates of returns from 1940-1980 at 12.4% vs. 12.5% for the 1985-2015 period. As a result of this, a balanced portfolio from 1940-1980 generated an average 8% return with a Sharpe ratio of 0.58, significantly lower than the average 10% return with Sharpe of 0.7 that we experienced in the last 30 years. In other words, in the only reasonable historical precedent a balanced portfolio generated lower nominal and risk adjusted returns than the post-1985 period. Now, I think backtests and historical references are a bit dangerous and overused by the financial community, but I also don’t think we need these historical precedents to establish a reasonable probability of future returns. All we need is a little common sense when comparing the next 30 years to the last 30 years. After all, we have empirical proof that most of those tailwinds are in fact waning. For instance: Current interest rates are the best predictor of future returns in the bond market, and this period is certain to be a low return period for future bond holders. Valuations, which have a strong tendency to correlate with future equity returns, are high historically. Demographic trends have shifted substantially in the last few decades from a world of higher growth to a much more modest pace of growth. High productivity gains have waned and have now become an area of great concern for economists. Corporate profits, as a share of national income, have never been higher as they rode the back of the liberalization of tax rates and regulation and could come under pressure given the anti-corporate climate we are entering. I don’t think any of this should be terribly controversial, and you don’t have to be an expert forecaster to see what’s coming. At the same time, we shouldn’t panic as some people have implied . If the aggregate stock and bond markets generate anything close to that 8% return of the 1940-1980 period, then most investors will still generate positive real returns. However, there are a few key takeaways here: It is crucial to understand the most important principles of portfolio construction so you can grow comfortable with a process and a plan. See Understanding Modern Portfolio Construction . It’s time to temper expectations in the markets. The future is likely to be an era of lower returns and potentially bumpier returns; however, it doesn’t mean returns are going to be catastrophic. It’s time to hunker down on your taxes and fees in your portfolio. As a % of assets, these frictions will become increasingly important in a lower return environment. See, Understanding your Real, Real Returns . Be patient! Find a good plan and learn to stick with it. The lower and bumpier returns will create periods of frustration for most investors. The grass will always look greener somewhere else. Switching in and out of plans and chasing the next hot guru will very likely result in higher taxes and fees, leading to lower average returns. See, How To Avoid the Problem of Short-Termism . Invest in yourself, continue to save and pour that savings into your portfolio. You might not get world beating returns from your portfolio in the coming 30 years, but we know cash will be the riskiest asset in the future as it will guarantee a negative real return in such a low interest rate environment. See, Saving is not the Key to Financial Success . Be careful reaching for yield. All safe assets aren’t created equal and reaching for yield in the wrong places could create more volatility without the guarantee of stable income. See, Reaching for Yield or Reaching for Risk? Don’t let the scaremongers get to you. If the future is one of lower returns and bumpier returns, there will be lines of people trying to sell you something in exchange for your fear. These people should not be trusted. The world of the future might not be the gangbusters growth period of the 80s and 90s, but it also won’t be the end of times either.

National Fuel Gas Company’s (NFG) CEO Ron Tanski on Q2 2016 Results – Earnings Call Transcript

National Fuel Gas Company (NYSE: NFG ) Q2 2016 Results Earnings Conference Call April 29, 2016 11:00 AM ET Executives Brian Welsch – Director of Investor Relations Ron Tanski – President and Chief Executive Officer Dave Bauer – Treasurer and Principal Financial Officer John McGinnis – Chief Operating Officer Analysts Kevin Smith – Raymond James Holly Stewart – Scotia Howard Becca Followill – U.S. Capital Advisors Operator Good day, ladies and gentlemen and welcome to the National Fuel Gas Company second-quarter 2016 earnings conference call. [Operator Instructions] I would now like to introduce your host for today’s conference, Mr. Brian Welsch, Director of Investor Relations. Please go ahead, sir. Brian Welsch Thank you, Christie and good morning. We appreciate you joining us on today’s conference call for a discussion of last evening’s earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer, Dave Bauer, Treasurer and Principal Financial Officer, and John McGinnis, Chief Operating Officer of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The second-quarter fiscal 2016 earnings release and April investor presentation have been posted on our investor relations website. We may refer to these materials during today’s call. We would also like to remind you that today’s teleconference will contain forward-looking statements. While National Fuel’s expectations, beliefs and projections are made in good faith, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made and you may refer to last evening’s earnings release for a listing of certain specific risk factors. With that I will turn it over to Ron Tanski. Ron Tanski Thanks, Brian and good morning everyone. Thanks for joining us for today’s call. As you saw in our earnings release last evening, we had a pretty steady second quarter although earnings were slightly down from last year. Earnings in our utility segment were lower due to warmer than normal weather and the lower commodity prices decreased earnings in our Exploration and Production segment. Dave Bauer will go into the details of the major earnings drivers later in the call. Overall, activities in the field for each of our operating segments moved right along as planned. We are just gearing up for the construction season for our regular pipeline renewal projects in our utility and our Pipeline and Storage segments. At the same time, we’ve slowed the drilling activities at Seneca Resources by moving to a single rig drilling program. Our reduced drilling level combined with getting a partner to fund a large portion of this year’s drilling program has cut our spending to allow us to leave within cash flow for the year. Our current plans allow us to stay to single drilling rig for at least a year before we need to ramp up drilling and completion activities again in order to have enough production to fill the pipeline capacity that will come online in November of 2017, the targeted completion date of our Northern Access pipeline. With respect to our Northern Access project, we received some good news from the Federal Energy Regulatory Commission. At April 14th, FERC issued its notices schedule for environmental review for the project and it confirmed their intention to develop an environmental assessment or EA for the project and announced the July 27, 2016 target date for the EA. Now that fits within our timeline for November 2017 in-service date. The other recent news on the regulatory front is the denial by the New York DEC of the Federal Water Quality Certification for the Constitution Pipeline project in Southeastern New York. We submitted our own permit filings to the New York DEC, the Pennsylvania Department of Environmental Protection and the U.S. Army Corps of Engineers for our project just last month. We delayed our filing by three months after a number of pre-filing meetings with the staff of the DEC in order to make sure that our application was complete and address their stated concerns. Based on those pre-filing meetings and gleaning what information we can from the Constitution denial letter, we feel our application is in pretty good shape. A big plus for our project is that more than 75% of the pipeline route will be co-located along existing utility corridors. We also believe that we worked well with the DEC in the past. We already owned and operated thousands of miles of pipeline assets in the state and during our ongoing maintenance and renewal of those lines we’ve dealt with them on a regular basis, addressing many project specific issues. Suffice it to say that we are confident that our project will continue to move along. On the federal rate regulatory front, our team has been busy filing the required cost and revenue study for our Empire Pipeline and answering interrogatories from FERC staff regarding the filing. The schedule is set out by the administrative law judge is a target completion date for the proceeding is set for February of 2017. So, we will keep you posted in future calls if anything major happens in that case. Switching to our utility and state rate regulation, our utility rate team filed a request for a rate increase in New York yesterday. This is the first rate increase request the utility has made since early 2007. The filing supports a $41.7 million increase in base rates, an increase of approximately $5.75 per month for an average residential customer. As is typical in the New York rate proceeding, any new rates would not become effective for 11 months. So, we wouldn’t expect any earnings impact until the second half of next fiscal year. We have a pretty clear line of sight through the end of this fiscal year with respect to our earnings projections and you can see that we’ve tightened up our earnings guidance range. With respect to our oil and gas production, we are well hedged for the remainder of this fiscal year and next fiscal year. And as you can see in the back pages of our earnings release, we are continuing our normal practice of layering in hedges for our oil and gas production as commodity prices in the futures market for our fiscal 2018 and beyond have begun to firm up. We see the market getting more bullish on commodity prices in the out years as production volumes have started to level off and the rig count stays low. For the foreseeable future, we will continue to watch our spending, protect our balance sheet and work to get our Northern Access pipeline build that will deliver Seneca’s production to an attractive pricing point. Now, I will turn the call over to John McGinnis, who will be stepping into the role of President at Seneca, when Matt Cabell’s retirement becomes effective next week. John McGinnis Thanks, Ron, and good morning everyone. For the fiscal second quarter, Seneca produced 39.2 Bcfe, which suggest over a Bcf more than we produced in our first quarter. In Pennsylvania, we curtailed approximately 9.1 Bcf of potential spot sales due to low prices and as a result, no spot gas was sold during the first half of our fiscal year. In April, however, prices have actually improved to the point but we have intermittently produced into the spot market at both our Tennessee and Transco receipt points. Though not a large volume totaling just over a Bcf, this was the first time we have sold meaningful spot volumes since December of 2014. In Pennsylvania after beginning the year with three rigs, we have now dropped to a single rig as of March. We plan on keeping this rig active for the remainder of the year to ensure we have sufficient inventory of DUCs to help fill Northern Access now scheduled to be online late next year. We have also reduced the activity level related to our completions crew to daylight-only operations. At this reduced pace, we typically complete five to six stages per day, which allows us to continue to recycle all of our produced water and avoid costly water disposal. Even with our frac crew operating at half pace, we continued to drop our well costs. For the first half of 2016, our development program has averaged under $5 million per well for a 7,400 foot lateral, which equates to costs of around $675 per foot. The key drivers for this continued drop in costs include the impact of the new frac contract executed in September of 2015 and a significant reduction in water costs. We now average less than a dollar per barrel in water costs, compared to about $3 per pad early in our development program. Moving now to the Utica/Point Pleasant, we have drilled and completed our first Clermont area at Utica horizontal at an estimated cost of just over $7 million. This well was drilled with a relatively short lateral length of 4,500 feet to better understand productivity on a per foot basis. Once we have completed all of 11 wells on this pad, 10 of which are in the Marcellus, we will bring this pad into production later this summer. The rig has recently moved to a new pad also in the Clermont area where we are currently drilling our second Utica well. This well is scheduled to be tested early in 2017. On the marketing front, when the opportunity arises, we continue to layer in fixed price sales and firm sales tied to financial hedges. This has allowed us to slowly grow production and realize acceptable pricing during an exceedingly difficult period for commodity prices. For the remainder of our fiscal 2016, the vast majority of our natural gas production forecast around 64 Bcf is locked in both physically and financially at an average realized price of $3.20. This $3.20 is net of firm transportation. We also have an additional 4 Bcf of basis protection and with the recent improvement in futures pricing, we are actively pursuing additional opportunities to add to our physical sales portfolio and hedge book. In California, production was nearly flat quarter-over-quarter, even though we have significantly cut our spending in California this year. We’re targeting to spend just under $40 million in 2016, almost a 30% reduction in compared to last year and half of what we spent just two years ago. All of our development activity is focused in Midway Sunset and will remain so until prices rebound. As a result of our recent farm-ins, however, we believe we can keep production flat to slightly growing over the next couple of years, even with these capital cuts. Thus far in 2016, we have cut E&P capital expenditures by almost 70% compared to 2015 levels to a forecasted range of $150 million to $200 million. Even with these cuts, we expect to grow our production slightly this year and maintain our DUC count ahead of Northern Access in-service date. The key drivers in achieving this result include our recent joint development agreement with IOG, dropping to a single rig and moving to daylight-only frac operations in Appalachia, combined with again, a significant reduction in our California capital expenditures. I’d like to now turn the call over to Dave Bauer. Dave Bauer Thanks, John. Good morning, everyone. Excluding the ceiling test charge, earnings for the quarter were $0.97 per share, down $0.05 from last year. The unseasonably warm weather in our service territory relative to last year’s record cold, lowered earnings by a combined $0.11 in our utility and Pipeline and Storage businesses. Meanwhile, our ongoing focus on cost control across the system helped to offset the continued weakness in oil and gas prices, which lowered earnings by about $0.25 per share. All told, considering the twin headwinds of weather and commodity pricing, both of which are largely beyond our control, the second quarter was a good one for National Fuel. Seneca’s production was up nearly 10% over last year’s quarter and 3% on a sequential basis. This increase is largely attributable to Seneca’s firm transportation capacity and associated firm sales related to the Northern Access 2015 project, which was placed in service late in calendar 2015. As a reminder, this was a joint project between our NFG Supply Corporation subsidiary and Tennessee Gas Pipeline designed to move a 140,000 dekatherms per day from our WDA acreage to the Canadian border at Niagara. For the quarter, this project contributed over $3 million in revenues to our Pipeline and Storage segment. In addition to benefiting Seneca and Supply Corp, the increase in Seneca’s production combined with our partner IOG’s share of the volumes from the joint development wells also helped our gathering business where revenues were up by $4.2 million or nearly 25%. Controlling operating costs was a focus across the system and we saw excellent results during the quarter. At Seneca, per unit LOE was $0.96 per Mcfe, down $0.07 from the first quarter. Most of this decrease was attributable to our California operations. In light of lower oil prices, our team has kept a tight lid on expenses, limiting our spending to only highly economic work-over activity and to areas that are critical to the safety and integrity of our assets. Also, lower natural gas prices caused steam fuel cost to be lower than we expected. In Appalachia, lower water disposal costs were also a factor. As John said, Seneca is now reusing almost 100% of our produced water. Road maintenance expense was also lower due to the relatively mild winter. Given all of these factors, we now expect our full-year per unit LOE rate will be in the range of $0.95 to a $1.05 per Mcfe, down $0.05 from our previous guidance. Seneca’s per unit G&A expense was $0.49 per Mcfe. During the quarter, Seneca implemented a reduction in force that trimmed our staffing complement by about 10%. As part of that effort, we paid out severance costs of about $1.5 million, which caused Seneca’s per unit G&A to be about $0.04 higher than it otherwise would’ve been. We’ll start to see lower personnel costs in the second half of the year. Per unit G&A for the rest of the fiscal year should be in the range of $0.35 to $0.40 per Mcfe. At utility, O&M costs were down over $5 million from last year. About a third of this decrease was caused by lower bad debt expense. A combination of historically warm weather and exceptionally low natural gas prices caused our customers winter heating bills to be the lowest they’ve seen in decades and has had a meaningful impact on our bad debt expense. The remainder of the decrease was caused by a variety of factors, including lower maintenance expense that was the result of the mild winter and lower pension and personnel-related expenses. In the Pipeline and Storage segment, revenues were up just about a $1 million from last year. While this may seem light, given the projects that were placed in service in the first quarter of the fiscal year, the swinging weather year-over-year had a significant impact on revenues from short-term firm services which decreased by approximately $5 million from last year. We expect larger favorable variances in revenue for the last two quarters of the year and still expect revenues in the segment to total between $300 million and $310 million for the full year. Looking to the remainder of the year, we are tightening our earnings and production guidance ranges. Our new earnings guidance while unchanged at the midpoint is a little tighter at $2.80 to $2.95, excluding ceiling test charges. Seneca’s updated production forecast is now a 158 to a 175 Bcfe. We up the low end of our previous guidance range of 150 to a 180 Bcfe to reflect new firm sales that were done this quarter, as well as some minor changes in our operations schedule. We lower the high end to reflect curtailments from the second quarter. As in prior quarters, the difference between the high and low end of our production range is driven entirely by curtailments. The low-end assumes we curtail a 100% percent of our spot production while the high-end assumes we have no curtailments. While we didn’t have any spot sales during the first six months of the year, as John mentioned we’ve sold about a Bcf spot sales in April which is encouraging. We have also made a modest change to our NYMEX natural gas price assumption which is now $2.15, down $0.10 from our previous guidance. Our oil price assumption is unchanged at $40 a barrel. We are well hedged for fiscal ‘16 for the remainder of the fiscal year and assuming the midpoint of our production guidance, we are about 80% hedged for natural gas and 55% for crude oil. Therefore, any changes in commodity prices should have a relatively modest impact on our cash flows. We continue to actively pursue incremental hedges in firm sales to lock in the economics of our program, as we grow into the volumes that are required to fill the Northern Access and Atlantic Sunrise projects. Just recently, we added a modest layer of Dawn and NYMEX-based hedges for 2018 to 2021 time period at about $3 per MMbtu. Consolidated capital spending for fiscal ‘16 is expected to be in the range of $445 million to $545 million, down $20 million from our previous range. Substantially, all of the change is related to the timing of spending between 2016 and 2017. Details of capital spending plans by segment are included in the new IR deck on our website. From a liquidity standpoint, we continued to be in great shape. Assuming the midpoint of our earnings and capital spending guidance, we expect we are very close within cash flows for the fiscal year. With that I will close and ask the operator to open the line for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from the line of Kevin Smith of Raymond James. Your line is open. Kevin Smith Thank you and good morning, gentlemen. John McGinnis Hi, Kevin. Kevin Smith John, congrats first on joining the earnings call but with that, I will kick off the question. Can you discuss current shut-in volumes in the Marcellus and maybe how much you’ve been able to sell to spot since differentials have been tightening? John McGinnis Say that again. I’m sorry, you are breaking up. Kevin Smith I apologize about that. Can you discuss current shut-in volumes in the Marcellus and then maybe how much you’ve been able to sell into spot and what that’s looked like over the last month? John McGinnis Yes. We’ve sold essentially nothing in spot for the second quarter, a little over a Bcf in April because prices had improved upon we could, both on Tennessee and Transco sell into the spot market. But recently though pricing has dropped off again so we are shut-in. But I think we are about $40 million to $50 million of available spot in our Tioga area and a little over 100, 120 in Lycoming if I remember correctly. Kevin Smith Got you. That’s helpful. And would you mind providing some more details about the new firm sales agreements? Basically what’s the length of those contracts? Dave Bauer Yes. Sure, Kevin. This is Dave. We did — well for fiscal ’16, we did about 5 Bcf of additional firm sales and then looking out into ’17, ’18, ’19, we did a bunch of fixed sales ranging, call it from 10 to 30 Bcf per year, kind of in the high but just under $2 range. Kevin Smith Okay. Great. That’s extremely helpful. That’s all I had. Thanks. Dave Bauer Sure. Operator Thank you. [Operator Instructions] And we do have a question from the line of Holly Stewart of Scotia Howard. Your line is open. Holly Stewart Good morning, gentlemen. John McGinnis Hi, Holly. Holly Stewart Maybe just one on sort of what you see on the capacity market in Northeast PA. I mean the rig count, I think in Northeast PA has dropped to maybe three now. Just curious if you’ve seen a pickup in capacity being offered out there and sort of what you are looking at in terms of volume, maybe a pickup in order to bring some of that volume on — some of your shut-in volume online? John McGinnis I think it’s actually down to two rigs now. I was just looking at that the other day. It continues to fall. We haven’t seen any help on the capacity side as of yet. Whether producers are bringing on wells as they had shut in, we just — we haven’t seen additional, at least significant additional capacity available in that part of the state. Holly Stewart Okay. Okay. Great. And then maybe you could just help us think about the progression of production for the next few quarters, give us your wells turned to sales during this past quarter and then sort of the remaining target for the year? John McGinnis Yes. I can give you our target for the year. I can’t tell you what the second quarter was. We are targeting for fiscal ‘16 about 50 wells to drilled, 45 to be completed. We will end the year with about 60 to 65 DUCs. And in terms of the well count, back half of the fiscal year, we are looking at bringing on an additional about 25 wells. Holly Stewart Okay. Great. Thanks, John. John McGinnis Yes. Operator Thank you. And our next question is from Becca Followill of U.S. Capital Advisors. Your line is open. Becca Followill Hi guys. John McGinnis Hi Becca. Becca Followill You talked a little bit. I know you’ve had the one-rig program. What does it take to start to ramp that back up again? John McGinnis Well, part of why we want to keep a single rig going is that it keeps in the half, sort of the daylight-only or what I call a half frac crew is that it keep our DUC count relatively flat. And so really to ramp-up, it doesn’t really — we are not going to necessarily need to bring in an extra rig. What we will end up doing is we will go to 24-hour frac crew and potentially two frac crews, obviously — depending on the ops and the in-service date related to Northern Access. So really it’s more to bring in an additional frac crews as opposed to a rig count. Becca Followill Thank you. And then on the water permit, what is the timing you’re expecting to get that permit from the DEC? John McGinnis Well, assuming that it takes the full year, Becca, it would be the beginning of March of 2017. Are you getting that? Becca Followill Do you think it will take the full year? John McGinnis I think we’ve — that’s kind of what we have planned at the outside. We had the luxury of being on 98% of the route sites, so that we had what we think was a very, very complete application. Whether that state will move it along any faster, we can’t guarantee. We just know that there is a year timeframe from filing. So that’s what we are planning on. Becca Followill Thank you. And then lastly on the Empire open season. I think there was something in the slide deck about precedent agreements were tendered in February. So, can you talk a little bit about that expansion? John McGinnis Well, we are working through that. We did have a good open season for the Empire North project. It was — to a certain degree it was oversubscribed because certain parties tried to put together different combinations of transportation routes and so that’s really what we’re working through, Becca, in order to kind of rationalize the best flows and the best combination and get that worked in to precedent agreements. We don’t have any of them signed just yet and we just continue to work away at that. Becca Followill Okay. Thank you. Operator Thank you. And our next question is from Chris Sighinolfi of Jefferies. Your line is open. Unidentified Analyst Hey guys. Good morning. This is actually Chris Dillon [ph] on for Sighinolfi. How are you? John McGinnis Hi, Chris. Dave Bauer Good, Chris. Unidentified Analyst I was just wondering if you could provide an update on the JV and whether or not you feel like the partner is likely to exercise the option there as we approach that date and what I guess, kind of conversations you are having and what might be under consideration from their side? John McGinnis The relationship is great. We drilled 30 of the 42 wells. With those pads just — they are early. They are just now coming online. Our costs have been about 10% or more down which they are pleased with. We have conversations around entering into the second tranche, but really that’s a decision that they are going to make in July and that’s really all I can speak to right now on that. Unidentified Analyst Okay. That’s fair. That was it for me. Thanks guys. Operator Thank you. And that does conclude our Q&A session for today. I would like to turn the call back to Mr. Brian Welsch for any further remarks. Brian Welsch Thank you, Christie. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, May 6, 2016. To access the replay online, please visit our investor relations website at investor.nationalfuelgas.com. And to access by telephone call 1-855-859-2056 and enter the conference ID number 84814628. This concludes our conference call for today. Thank you and goodbye. Operator Ladies and gentlemen, thank you for participating in today’s conference. This does conclude today’s program. You may all disconnect. Everyone have a great day. 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. 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