Tag Archives: political

Optical Illusion / Optical Truth

A great deal of intelligence can be invested in ignorance when the need for illusion is deep. – Saul Bellow, “To Jerusalem and Back” (1976) It is difficult to get a man to understand something, when his salary depends on his not understanding it. – Upton Sinclair, “I, Candidate for Governor: And How I Got Licked” (1935) Knowledge kills action; action requires the veils of illusion. – Friedrich Nietzsche, “The Birth of Tragedy” (1872) To find out if she really loved me, I hooked her up to a lie detector. And just as I suspected, my machine was broken. – Jarod Kintz, “Love Quotes for the Ages. Specifically Ages 19-91” (2013) Edward Tufte is a personal and professional hero of mine. Professionally, he’s best known for his magisterial work in data visualization and data communication through such classics as The Visual Display of Quantitative Information (1983) and its follow-on volumes, but less well-known is his outstanding academic work in econometrics and statistical analysis. His 1974 book Data Analysis for Politics and Policy remains the single best book I’ve ever read in terms of teaching the power and pitfalls of statistical analysis. If you’re fluent in the language of econometrics (this is not a book for the uninitiated) and now you want to say something meaningful and true using that language, you should read this book (available for $2 in Kindle form on Tufte’s website ). Personally, Tufte is a hero to me for escaping the ivory tower, pioneering what we know today as self-publishing, making a lot of money in the process, and becoming an interesting sculptor and artist. That’s my dream. That one day when the Great Central Bank Wars of the 21st century are over, I will be allowed to return, Cincinnatus-like, to my Connecticut farm where I will write short stories and weld monumental sculptures in peace. That and beekeeping. But until that happy day, I am inspired in my war-fighting efforts by Tufte’s skepticism and truth-seeking. The former is summed up well in an anecdote Tufte found in a medical journal and cites in Data Analysis : One day when I was a junior medical student, a very important Boston surgeon visited the school and delivered a great treatise on a large number of patients who had undergone successful operations for vascular reconstruction. At the end of the lecture, a young student at the back of the room timidly asked, “Do you have any controls?” Well, the great surgeon drew himself up to his full height, hit the desk, and said, “Do you mean did I not operate on half of the patients?” The hall grew very quiet then. The voice at the back of the room very hesitantly replied, “Yes, that’s what I had in mind.” Then the visitor’s fist really came down as he thundered, “Of course not. That would have doomed half of them to their death.” God, it was quiet then, and one could scarcely hear the small voice ask, “Which half?” ‘Nuff said. The latter quality – truth-seeking – takes on many forms in Tufte’s work, but most noticeably in his constant admonitions to LOOK at the data for hints and clues on asking the right questions of the data. This is the flip-side of the coin for which Tufte is best known, that good/bad visual representations of data communicate useful/useless answers to questions that we have about the world. Or to put it another way, an information-rich data visualization is not only the most powerful way to communicate our answers as to how the world really works, but it is also the most powerful way to design our questions as to how the world really works. Here’s a quick example of what I mean, using a famous data set known as “Anscombe’s Quartet”. Anscombe’s Quartet I II III IV x y x y x y x y 10.0 8.04 10.0 9.14 10.0 7.46 8.0 6.58 8.0 6.95 8.0 8.14 8.0 6.77 8.0 5.76 13.0 7.58 13.0 8.74 13.0 12.74 8.0 7.71 9.0 8.81 9.0 8.77 9.0 7.11 8.0 8.84 11.0 8.33 11.0 9.26 11.0 7.81 8.0 8.47 14.0 9.96 14.0 8.10 14.0 8.84 8.0 7.04 6.0 7.24 6.0 6.13 6.0 6.08 8.0 5.25 4.0 4.26 4.0 3.10 4.0 5.39 19.0 12.50 12.0 10.84 12.0 9.13 12.0 8.15 8.0 5.56 7.0 4.82 7.0 7.26 7.0 6.42 8.0 7.91 5.0 5.68 5.0 4.74 5.0 5.73 8.0 6.89 In this original example (developed by hand by Frank Anscombe in 1973; today there’s an app for generating all the Anscombe sets you could want) Roman numerals I – IV refer to four data sets of 11 (x,y) coordinates, in other words 11 points on a simple 2-dimensional area. If you were comparing these four sets of numbers using traditional statistical methods, you might well think that they were four separate data measurements of exactly the same phenomenon. After all, the mean of x is exactly the same in each set of measurements (9), the mean of y is the same in each set of measurements to two decimal places (7.50), the variance of x is exactly the same in each set (11), the variance of y is the same in each set to two decimal places (4.12), the correlation between x and y is the same in each set to three decimal places (0.816), and if you run a linear regression on each data set you get the same line plotted through the observations (y = 3.00 + 0.500x). But when you LOOK at these four data sets, they are totally alien to each other, with essentially no similarity in meaning or probable causal mechanism . Of the four, linear regression and our typical summary statistical efforts make sense for only the upper left data set. For the other three, applying our standard toolkit makes absolutely no sense. But we’d never know that – we’d never know how to ask the right questions about our data – if we didn’t eyeball it first. Click to enlarge Okay, you might say, duly noted. From now on we will certainly look at a visual plot of our data before doing things like forcing a line through it and reporting summary statistics like r-squared and standard deviation as if they were trumpets of angels from on high. But how do you “see” multi-variate datasets? It’s one thing to imagine a line through a set of points on a plane, quite another to visualize a plane through a set of points in space, and impossible to imagine a cubic solid through a set of points in hyperspace. And how do you “see” embedded or invisible data dimensions, whether it’s an invisible market dimension like volatility or an invisible measurement dimension like time aggregation or an invisible statistical dimension like the underlying distribution of errors ? The fact is that looking at data is an art, not a science. There’s no single process, no single toolkit for success. It requires years of practice on top of an innate artist’s eye before you have a chance of being good at this, and it’s something that I’ve never seen a non-human intelligence accomplish successfully (I can’t tell you how happy I am to write that sentence). But just because it’s hard, just because it doesn’t come easily or naturally to people and machines alike … well, that doesn’t mean it’s not the most important thing in data-based truth-seeking. Why is it so important to SEE data relationships? Because we’re human beings. Because we are biologically evolved and culturally trained to process information in this manner. Because – and this is the Tufte-inspired market axiom that I can’t emphasize strongly enough – the only investable ideas are visible ideas . If you can’t physically see it in the data, then it will never move you strongly enough to overcome the pleasant fictions that dominate our workaday lives, what Faust’s Tempter, the demon Mephistopheles, calls the “masquerade” and “the dance of mind.” Our similarity to Faust (who was a really smart guy, a man of Science with a capital S) is not that the Devil may soon pay us a visit and tempt us with all manner of magical wonders, but that we have already succumbed to the blandishments of easy answers and magical thinking. I mean, don’t get me started on Part Two, Act 1 of Goethe’s magnum opus, where the Devil introduces massive quantities of paper money to encourage inflationary pressures under a false promise of recovery in the real economy. No, I’m not making this up. That is the actual, non-allegorical plot of one of the best, smartest books in human history, now almost 200 years old. So what I’m going to ask of you, dear reader, is to look at some pictures of market data, with the hope that seeing will indeed spark believing. Not as a temptation, but as a talisman against the same. Because when I tell you that the statistical correlation between the US dollar and the price of oil since Janet Yellen and Mario Draghi launched competitive monetary policies in mid-June of 2014 is -0.96 I can hear the yawns. I can also hear my own brain start to pose negative questions, because I’ve experienced way too many instances of statistical “evidence” that, like the Anscombe data sets, proved to be misleading at best. But when I show you what that correlation looks like … Click to enlarge © Bloomberg Finance L.P., for illustrative purposes only I can hear you lean forward in your seat. I can hear my own brain start to whir with positive questions and ideas about how to explore this data further. This is what a -96% correlation looks like. What you’re looking at in the green line is the Fed’s favored measure of what the US dollar buys around the world. It’s an index where the components are the exchange rates of all the US trading partners (hence a “broad dollar” index) and where the individual components are proportionally magnified/minimized by the size of that trading relationship (hence a “trade-weighted” index). That index is measured by the left hand vertical axis, starting with a value of about 102 on June 18, 2014 when Janet Yellen announced a tightening bias for US monetary policy and a renewed focus on the full employment half of the Fed’s dual mandate, peaking in late January and declining to a current value of about 119 as first Japan and Europe called off the negative rate dogs (making their currencies go up against the dollar) and then Yellen completely back-tracked on raising rates this year (making the dollar go down against all currencies). Monetary policy divergence with a hawkish Fed and a dovish rest-of-world makes the dollar go up. Monetary policy convergence with everyone a dove makes the dollar go down. What you’re looking at in the magenta line is the upside-down price of West Texas Intermediate crude oil over the same time span, as measured by the right hand vertical axis. So on June 18, 2014 the spot price of WTI crude oil was over $100/barrel. That bottomed in the high $20s just as the trade-weighted broad dollar index peaked this year, and it’s been roaring back higher (lower in the inverse depiction) ever since. Now correlation may not imply causation, but as Ed Tufte is fond of saying, it’s a mighty big hint. I can SEE the consistent relationship between change in the dollar and change in oil prices, and that makes for a coherent, believable story about a causal relationship between monetary policy and oil prices. What is that causal narrative? It’s not just the mechanistic aspects of pricing, such that the inherent exchange value of things priced in dollars – whether it’s a barrel of oil or a Caterpillar earthmover – must by definition go down as the exchange value of the dollar itself goes up. More impactful, I think, is that for the past seven years investors have been well and truly trained to see every market outcome as the result of central bank policy, a training program administered by central bankers who now routinely and intentionally use forward guidance and placebo words to act on “the dance of mind” in classic Mephistophelean fashion. In effect, the causal relationship between monetary policy and oil prices is a self-fulfilling prophecy (or in the jargon du jour, a self-reinforcing behavioral equilibrium), a meta-example of what George Soros calls reflexivity and what a game theorist calls the Common Knowledge Game . The causal relationship of the dollar, i.e. monetary policy, to the price of oil is a reflection of the Narrative of Central Bank Omnipotence , nothing more and nothing less. And today that narrative is everything. Here’s something smart that I read about this relationship between oil prices and monetary policy back in November 2014 when oil was north of $70/barrel: I think that this monetary policy divergence is a very significant risk to markets, as there’s no direct martingale on how far monetary policy can diverge and how strong the dollar can get. As a result I think there’s a non-trivial chance that the price of oil could have a $30 or $40 handle at some point over the next 6 months, even though the global growth and supply/demand models would say that’s impossible. But I also think the likely duration of that heavily depressed price is pretty short. Why? Because the Fed and China will not take this lying down. They will respond to the stronger dollar and stronger yuan (China’s currency is effectively tied to the dollar) and they will prevail, which will push oil prices back close to what global growth says the price should be. The danger, of course, is that if they wait too long to respond (and they usually do), then the response will itself be highly damaging to global growth and market confidence and we’ll bounce back, but only after a near-recession in the US or a near-hard landing in China. Oh wait, I wrote that . Good stuff. But that was a voice in the wilderness in 2014, as the dominant narrative for the causal factors driving oil pricing was all OPEC all the time. So what about that, Ben? What about the steel cage death match within OPEC between Saudi Arabia and Iran and outside of OPEC between Saudi Arabia and US frackers? What about supply and demand? Where is that in your price chart of oil? Sorry, but I don’t see it in the data . Doesn’t mean it’s not really there. Doesn’t mean it’s not a statistically significant data relationship. What it means is that the relationship between oil supply and oil prices in a policy-controlled market is not an investable relationship. I’m sure it used to be, which is why so many people believe that it’s so important to follow and fret over. But today it’s an essentially useless exercise in data analytics. Not wrong, but useless … there’s a difference! Of course, crude oil isn’t the only place where fundamental supply and demand factors are invisible in the data and hence essentially useless as an investable attribute. Here’s the dollar and something near and dear to the hearts of anyone in Houston, the Alerian MLP index, with an astounding -94% correlation: Click to enlarge © Bloomberg Finance L.P., for illustrative purposes only Interestingly, the correlation between the Alerian MLP index and oil is noticeably less at -88%. Hard to believe that MLP investors should be paying more attention to Bank of Japan press conferences than to gas field depletion schedules, but I gotta call ’em like I see ’em. And here’s the dollar and the iShares MSCI Emerging Markets ETF ( EEM), the dominant emerging market ETF, with a -89% correlation: Click to enlarge © Bloomberg Finance L.P., for illustrative purposes only There’s only one question that matters about Emerging Markets as an asset class, and it’s the subject of one of my first (and most popular) Epsilon Theory notes, ” It Was Barzini All Along “: are Emerging Market growth rates a function of something (anything!) particular to Emerging Markets, or are they simply a derivative function of Developed Market central bank liquidity measures and monetary policy? Certainly this chart suggests a rather definitive answer to that question! And finally, here’s the dollar and the US Manufacturing PMI survey of real-world corporate purchasing managers, probably the most respected measure of US manufacturing sector health. This data relationship clocks in at a -92% correlation. I mean … this is nuts. Click to enlarge © Bloomberg Finance L.P., for illustrative purposes only Here’s what I wrote last summer about the inexorable spread of monetary policy contagion. Monetary policy divergence manifests itself first in currencies, because currencies aren’t an asset class at all, but a political construction that represents and symbolizes monetary policy. Then the divergence manifests itself in those asset classes, like commodities, that have no internal dynamics or cash flows and are thus only slightly removed in their construction and meaning from however they’re priced in this currency or that. From there the divergence spreads like a cancer (or like a cure for cancer, depending on your perspective) into commodity-sensitive real-world companies and national economies. Eventually – and this is the Big Point – the divergence spreads into everything, everywhere. I think this is still the only story that matters for markets. The good Lord giveth and the good Lord taketh away. Right now the good Lord’s name is Janet Yellen, and she’s in a giving mood. It won’t last. It never does. But it does give us time to prepare our portfolios for a return to competitive monetary policy actions , and it gives us insight into what to look for as catalysts for that taketh away part of the equation. Most importantly, though, I hope that this exercise in truth-seeking inoculates you from the Big Narrative Lie coming soon to a status quo media megaphone near you, that this resurgence in risk assets is caused by a resurgence in fundamental real-world economic factors. I know you want to believe this is true. I do, too! It’s unpleasant personally and bad for business in 2016 to accept the reality that we are mired in a policy-controlled market, just as it was unpleasant personally and bad for business in 1854 to accept the reality that cholera is transmitted through fecal contamination of drinking water. But when you SEE John Snow’s dot map of death you can’t ignore the Broad Street water pump smack-dab in the middle of disease outcomes. When you SEE a Bloomberg correlation map of prices you can’t ignore the trade-weighted broad dollar index smack-dab in the middle of market outcomes. Or at least you can’t ignore it completely. It took another 20 years and a lot more cholera deaths before Snow’s ideas were widely accepted. It took the development of a new intellectual foundation: germ theory. I figure it will take another 20 years and the further development of game theory before we get widespread acceptance of the ideas I’m talking about in Epsilon Theory . That’s okay. The bees can wait.

ONEOK’s (OKE) CEO Terry Spencer on Q1 2016 Results – Earnings Call Transcript

ONEOK, Inc. (NYSE: OKE ) Q1 2016 Results Earnings Conference Call May 04, 2016, 11:00 AM ET Executives T.D. Eureste – Investor Relations Terry Spencer – President and Chief Executive Officer Walt Hulse – Executive Vice President of Strategic Planning and Corporate Affairs Derek Reiners – Chief Financial Officer Wes Christensen – Senior Vice President, Operations Sheridan Swords – Senior Vice President, Natural Gas Liquids Kevin Burdick – Senior Vice President, Natural Gas Gathering and Processing Phillip May – Senior Vice President, Natural Gas Pipelines Analysts Eric Genco – Citi Brian Gamble – Simmons and Company Danilo Juvane – BMO Capital Markets Christine Cho – Barclays Craig Shere – Tuohy Brothers Becca Followill – US Capital Advisors Shneur Gershuni – UBS Jeremy Tonet – JPMorgan John Edwards – Credit Suisse Operator Please stand-by, we are about to begin. Good day, ladies and gentlemen, and welcome to the First Quarter 2016 ONEOK and ONEOK Partners Earnings Call. Today’s conference is being recorded. At this time, I’d like to turn the conference over to today’s host Mr. T.D. Eureste. Please go ahead, sir. T.D. Eureste Thank you, and welcome to ONEOK and ONEOK Partners’ first quarter 2016 earnings conference call. A reminder that statements made during this call that might include ONEOK or ONEOK Partners’ expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provisions of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker is Terry Spencer, President and CEO of ONEOK and ONEOK Partners. Terry? Terry Spencer Thank you, T.D. Good morning, and thank you for joining today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners. On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, Chief Financial Officer; and Senior Vice Presidents, Wes Christensen, Operations; Sheridan Swords, Natural Gas Liquids; Kevin Burdick, Natural Gas Gathering and Processing; and Phil May, Natural Gas Pipelines. I’ll begin with a few opening remarks, then Derek will give a brief financial update and then I will wrap up with highlights of the first quarter, our outlook for the remainder of the year and our ethane opportunity. To begin, first quarter 2016 performance was a result of the progress made last year by continuing to focus on increasing our fee-based earnings, reducing commodity price risks in our businesses, project execution and making prudent financial decisions all while continuing to operate safely and responsibly. In this challenging market conditions, we have relied on our strengths, which for ONEOK Partners are predominantly fee-based earnings, our uniquely positioned assets and our dedicated employees. Our competitive advantage is our integrated network of assets that fit and work well together. Our 37,000-mile network of pipelines, processing plants and fractionators are well positioned to withstand the cyclical nature of the industry. Our assets in the Williston Basin have served us well, and we continue to benefit from the basin’s large natural gas reserve base and inventory of flared NGL-rich natural gas. Our Natural Gas Pipeline segment remained well positioned to expand its fee-based natural gas export capabilities, particularly to Mexico where we have key relationships through our joint venture Roadrunner Gas Transmission Pipeline and our extensive Natural Gas Liquids business maintains a growing position in the Rockies, Texas and emerging STACK and SCOOP plays in Oklahoma, providing us a large and diversified base with which to serve our end-use customers. The partnership’s distribution coverage increased to 1.06 times in the first quarter, up from 1.03 times in the fourth quarter 2015 and significantly higher compared to the beginning of 2015 which is a reflection of our increasing stable cash flow as we now have a significant amount of infrastructure completed and are able to harvest earnings, particularly in the Gathering and Processing and Natural Gas Liquids businesses. ONEOK Partners first quarter 2016 adjusted EBITDA of approximately $445 million represents a nearly 40% increase compared with the first quarter 2015. Executing on our growth projects, contract restructuring, capital and cost savings and consistent operations were key drivers to delivering the greatly improved results from a year ago, even in the face of deteriorating industry fundamental throughout 2015. From an operating perspective, volume growth across our businesses, increased fee-based earnings, and ongoing cost reduction efforts across ONEOK Partners business segments have all contributed to a solid first quarter and positive outlook for the remainder of 2016. In the midst of some of the industry’s most challenging conditions, our employees once again performed exceptionally well by successfully executing on our strategies to mitigate risk, reduce capital spending and operating costs, and manage our balance sheet. It is through their hard work and determination that our company delivered impressive results quarter after quarter in 2015, and we remain as committed as ever to delivering even better results in 2016. Through our key strategies and well managed and operated assets, our employees have, with a high sense of urgency, met the challenge, just as they have many times in the past. I’d like to thank them for their hard work and commitment to deliver value to the bottom line safely and reliably. We’ll cover each of the segments in more detail later in the call, but first I’d like to have Derek give us some brief financial update. Derek? Derek Reiners Thanks, Terry. Both ONEOK and ONEOK Partners ended the first quarter in a strong financial position with healthy balance sheets and ample financial flexibility. As Terry mentioned, ONEOK Partners first quarter distribution coverage was 1.06 times. ONEOK’s first quarter dividend coverage was 1.31 times, which together with cash on hand entering the year maintains ONEOK flexibility to provide financial support to the partnership if needed. In yesterday’s earnings news releases, we maintained our 2016 financial guidance expectations for both ONEOK and ONEOK Partners. Our proactive financial actions in 2015 and early 2016 and enhanced earnings from the partnership has allowed the partnership to deliver on distribution coverage, while also reducing leverage. The partnership’s capital expenditure guidance remains $600 million, including $140 million of maintenance capital for 2016, as the reliability and integrity of our assets is the foundation of our success. However, we are seeing aggressive bidding from our vendors on maintenance projects and the timing associated with our maintenance activities can vary significantly from quarter to quarter due to seasonal impacts in varying maintenance cycles across our ever-changing asset base. Typically our maintenance capital spending is lower in the first quarter. Sequentially maintenance capital decreased $8 million in the first quarter, primarily due to our maintenance project plan for the quarter having fewer projects compared to the fourth quarter, which is not unusual when compared to our historical spending profile. We are on plan for our scheduled maintenance projects for 2016. Similarly, as it relates to operating cost, we continue to see competitive, lower pricing and rates from service providers and we have significantly reduced contract labor across all of our segments. In the first quarter we realized $15 million sequential decrease in operating cost. And as Terry mentioned, we continue to focus on internal operating cost reduction efforts company-wide. We expect these cost savings to continue throughout the year. In January, ONEOK Partners entered into $1 billion three-year unsecured term loan, effectively refinancing our 2016 debt maturities and enhancing financial flexibility. With approximately $1.9 billion of capacity available on the ONEOK Partners credit facility at the end of the first quarter, the reduction of more than $2.2 billion in capital growth projects in two years and higher earnings, the partnership does not need to access public debt or equity markets well into 2017. The partnership continues to progress towards deleveraging as our trailing 12 months’ GAAP debt to EBITDA improved to 4.5 times at March 31st. And we continue to expect annual GAAP debt to EBITDA ratio of 4.2 times for the full year 2016 as a result of prudent financial, operating and commercial execution. As always, we remain committed to the partnership’s investment grade credit ratings. On a standalone basis, ONEOK ended the first quarter with nearly $130 million of cash and expects to have approximately $250 million of cash by year-end 2016 and an undrawn $300 million credit facility, allowing us financial flexibility as we continue to navigate a challenging market environment. In February, we provided detailed information on our counterparty credit risk. We’ve included similar information again this year in our Form 10-Q but there haven’t been any substantial changes. We have a very high quality customer base and no material counterparty credit concerns. The majority of our top customers are large petrochemical and integrated oil companies, which have a higher tolerance for volatility and commodity prices. Our track record of prudent and proactive financial decisions during uncertain times resulted in ample liquidity, too strong balance sheets, and a strong customer base. ONEOK and ONEOK Partners remain well positioned to withstand a volatile commodity and financial market environment. Terry, that concludes my remarks. Terry Spencer Thank you, Derek. Let’s take a closer look at each of our business segments. In the Natural Gas Liquids segment, volumes continued to increase year-over-year with first quarter 2016 volumes gathered up 6% and volumes fractionated up 16% compared with the first quarter of 2015. Compared with the fourth quarter 2015, volumes gathered and fractionated were lower primarily due to decreased spot volumes, higher ethane rejection and seasonal impacts. We continue to expect NGL volumes to be weighted toward the second half of the year as incremental volumes from new natural gas processing plant connections continue to ramp up. In the first quarter, we connected three additional third-party plants to our NGL system and we continue to see volumes ramp at the eight plants we connected in 2015. We expect to connect one additional third-party plant this year in addition to completing and connecting our 80 million cubic feet per day Bear Creek plant in the Williston Basin where additional flared natural gas remains ready to come online. Williston Basin NGL volumes, our highest margin NGL volumes with bundled rates more than three times of those in other regions, remained strong in the first quarter. The average volume gathered on our Bakken NGL Pipeline increased nearly 12% compared with the fourth quarter 2015, driven by the completion of the Lonesome Creek plant in November 2015 and compression project. I’ll also talk about ethane and provide an update on our ethane opportunity outlook in just a moment. As it relates to the West Texas LPG system, in July 2015, we increased rates on this system to be more in line with market rates. In March, the Texas Railroad Commission suspended the rate increase until it is determined by the Commission if the rates are in line with the market. We are confident that our increased rates are just in reasonable and in line with the market. However, regardless of the outcome of the pending case, our current 2016 financial guidance remains as indicated. As you all can appreciate, due to the legal process now underway with the railroad commission, it will not be prudent at this time for us to discuss this case in any more detail. We will provide future updates or commentary when and if it is appropriate. In the Natural Gas Gathering and Processing segment, Williston Basin volumes were a key driver to our first quarter performance. Our Natural Gas volumes processed reached 810 million cubic feet per day as we captured previously flared gas and connected new wells to our system. Average natural gas volumes processed in the Williston increased 44% in the first quarter 2016 compared with the first quarter last year, and increased 6% compared with the fourth quarter 2015. Our producer customers continue to drive improvements in initial production rates through enhanced completion techniques, and combined with the higher natural-gas-to-oil ratios in the core areas where virtually all of our new wells are being connected, have helped offset the reduction in drilling and completion activity. We will continue to benefit from more than 820 wells connected in 2015 and the 115 wells connected to our system in the first quarter 2016. The vast majority of these high performing wells are in the most productive areas of Williams, McKenzie, and Dunn counties in North Dakota where we have more than a million acres dedicated to us and an extensive network of interconnected gathering lines, compression, and processing plants. There are currently 900 drilled but uncompleted wells in the basin, with nearly 400 on our acreage. We saw a decline in the drilling rig count across the Williston Basin during the first quarter and currently have approximately 15 rigs operating on our acreage under dedication. Flared natural gas in North Dakota was reported at approximately 185 million cubic feet per day for the state in February, with approximately 70 to 80 million cubic feet per day on our system. This continues to present an opportunity for us as we add processing capacity to our system in the third quarter 2016 with the completion of our Bear Creek natural gas processing plant. In the Mid-Continent, first quarter 2016 processed volumes increased 8% compared with fourth quarter 2015 volumes. Similar to the Williston, our producer customers continue to drive significant increases in initial production rates through enhanced completion techniques, especially in the STACK, Cana-Woodford and SCOOP plays. Procedure delays on completions of some large multi-well pads are expected to impact our volumes over the next several months and potentially through the remainder of 2016. However with the recent improvement in commodity prices and breakevens in the STACK competing favourably with the best plays in the country, we could see acceleration of the delayed completions. Contract restructuring in the Natural Gas Gathering and Processing segment has significantly decreased the segment’s commodity price sensitivity and was another major contributor to the partnership’s first quarter results. The segments average fee rate increased to $0.68 per MMBtu, compared with $0.35 in the same period last year and $0.55 in the fourth quarter 2015. We expect the segment’s earnings to increase to more than 75% fee-based this year, driven by this contract restructuring efforts. Moving on to the Natural Gas Pipeline segment, first quarter results remained steady as the segment continued to provide the partnership with stable, predominantly fee-based earnings. The segment completed two capital growth projects in March, the first phase of the Roadrunner Gas Transmission pipeline project and a compressor station expansion project on our Midwestern Gas Transmission pipeline which will add an additional 170 million cubic feet per day of capacity to the pipeline. The Roadrunner project is fully subscribed under 25-year firm fee-based commitment and the second phase of the Roadrunner is expected to be complete in the first quarter 2017. Additionally, the Midwestern Gas Transmission expansion is also fully subscribed under 15-year firm fee-based commitments. Our Natural Gas Pipelines segment is primarily market connected, meaning we are directly connected with large stable customers who provide services to end users. These customers such as large utility companies, electric generation facilities and industrials have specific volume needs that don’t fluctuate based on commodity prices. Additionally, we work closely with these customers to design our systems to fit their specific needs. Unlike basis-driven pipelines, there is minimal financial risk associated with our Natural Gas Pipelines or our customers. We like the stability of our Natural Gas Pipelines business and the customers we serve, and we’ll continue to develop additional fee-based and market-driven long-term growth and export opportunities in and around our asset footprint. I’d like to close by providing an update on our ethane opportunity outlook. For the past three years our industry has experienced an unprecedented period of heavy and prolonged ethane rejection. The partnership continued even in the face of sustained ethane rejection to increase our Natural Gas Liquids volumes gathered and fractionated. We are starting to see ethane prices improve in relation to Natural Gas as a result of improving NGL prices and weakened natural gas, increases in NGL exports and expected incremental ethane demand from new world scale petrochemical crackers. Since last quarter, we’ve seen ethane recovery economics improve. Some natural gas processing plants on our system have intermittently started to recover ethane, which we expect to continue throughout 2016. We continue to expect a meaningful amount of processing plants to move into full recovery in early 2017. We average 175,000 barrels per day of ethane rejection on our system in the first quarter, and we expect anywhere from 175,000 to 200,000 barrels per day of ethane rejection on our system as new natural gas plants, we are connected to, continue to ramp up, and as we see the impacts of increased volumes in the Williston, STACK and SCOOP plays throughout 2016. We are well positioned to benefit from this ethane opportunity and have more than enough infrastructure to bring these incremental barrels or approximately $200 million in annual earnings to our system with no additional capital requirements. We also have the opportunity to utilize our assets to capture pricing differentials if any dislocations in pricing occur between the Conway, Kansas and Mont Belvieu, Texas market centres as a result of increasing ethane demand. Ethane recovery presents a major opportunity for ONEOK and ONEOK Partners, but it certainly isn’t our only opportunity. We remain focussed on additional fee-based growth opportunities for our businesses, cost effective ways to enhance our assets, and employee retention efforts. So we are fully prepared when market conditions improve. Congratulations to our employees on a solid first quarter. We continue to face headwinds from challenging industry conditions, but we’ve shown once again that we’re uniquely positioned to handle these challenges and deliver on the financial results we’ve laid out for ourselves and our investors. Thank you to all of our stakeholders for your continued support of ONEOK and ONEOK Partners. Operator, we’re now ready for questions. Question-and-Answer Session Operator Thank you sir. [Operator Instructions]. We’ll pause for just a moment to allow everyone an opportunity to signal for questions. And we will take our first question from Eric Genco with Citi. Eric Genco Hey, good morning. I have a couple of follow-up questions on ethane. Just wanted to kind of go over. I think you mentioned it basically, but in moving to 175,000 to 200,000 barrels a day of ethane opportunity in ’16 versus the 150,000 to 180,000 last quarter being rejected, is that basically — that’s basically third-party plant and a shift towards more liquid rich drilling overtime, is that what’s accounting for that increase? Terry Spencer Yes, Eric I think, yes, most of that is a result of the new plants that we’ve connected here fairly recently. And, of course, the growth that we’re seeing behind those facilities that we indicated in my remarks, so, yes, most of that is from the new plants. Sheridan, anything? Sheridan Swords No, that’s it. Eric Genco All right. And I guess the other thing I was kind of curious about is we’ve been sort of talking about this little bit more, just trying to get a better handle on some of the ethane recoveries that are likely to come out of the Bakken eventually. And so I think I understand based on bundled costs and how that works economically, and you guys have said that basically that Bakken would theoretically be one of the later basins to be culled. But I’m also curious too because I know — you know, you’ve referred to some of your services being non-discretionary in the past and it’s not like ethane economics specifically is going to drive drilling in the Bakken. So I’m curious is there a way to look at or think about pipeline stacks in the Bakken and sort of — you know, as things come back, just sort of push ethane recovery and how that might impact you. Is there any way to sort of numerically think about that or is that still something that will just have to kind of wait beyond? Terry Spencer You know, Eric, broadly as you think about where we deliver ethane across our systems, we really don’t have any quality issues or any concerns really on a large scale. We may periodically in certain specific locations dependent upon the location of those pipes to end-user, we sometimes do have some issues with respect to quality specs, but I don’t see quality specs being a big driver for ethane emerging from the Bakken, nor really anywhere else for that matter. And when we talk about these non-discretionary services, we talk about producers have to have the process and they got to have the liquids extracted from the gas in order to meet quality specs. Ethane tends to be one of those — is one of those NGLs that can be — can easily go into the gas train and be diluted without causing much of a problem, unless you’ve got industrial customers or commercial customers right near — located in pretty close proximity to the processing plant, okay? That helped you? Eric Genco Yes, it does. Thank you very much. I appreciate your time. Operator And we will go next to Brian Gamble with Simmons and Company. Brian Gamble Good morning, everybody. Terry Spencer Good morning, Brian. Brian Gamble On the Natural Gas Gathering and Processing segment, that fee rates increase obviously excellent year-over-year and even quarter-over-quarter. I know that we’d talked about some of those new contracts hitting in January and that creates a bump. Maybe you could walk us through how we should think about that rate moving through the year. I think there is some contract that come up mid-year, maybe some Mid-Con things. But if I remember correctly, there was a pretty healthy chunk of the Williston that they got repriced? And just want to make sure, being realistic about how I’m thinking about that rate for the rest of the year. Terry Spencer Yes, I’ll just make a couple of general comments and I’ll turn it over to Kevin. You know, as far as our contract restructuring effort, the lion share of the contracts or the bulk of what we set out to do in the Williston Basin, that’s done. And so don’t expect a whole lot more to occur. There’s still some work in progress, but don’t expect a whole lot more impact from that. The Mid-Continent is just going to continue to be work-in-progress. We have a much larger producer base of, that is, we have a lot more procedures that have much smaller volumes and consequently it takes — it’s a lot more involved in the Mid-Continent than in the Williston, just because of the sheer number of contracts that we’re talking about. So that’s caught from in a broad sense. Kevin, you’ve got anything else to add to that. Kevin Burdick No, I think that’s right on. Brian Gamble That works. And then as far as the connections in the Williston, you mentioned 115 wells, I believe, you said in Q1. You mentioned the flared gas that’s still on the system as well as the potential duct completions that would go in. But as far as well count adds that you’re anticipating for the rest of the year, are there wells that are completed that are sitting there that now the system can handle that we’re working on, or are we waiting for ducts for the majority of the opportunity to, I guess, incrementally add new wells to the system more for this year? Kevin Burdick Brian, this is Kevin. Yes, that will come from — the way we think about connecting the wells, it will come from a couple of — from both of those places. I mean as rigs continue to work the basin as those wells that are being drilled or completed, we’ll connect those up. But there is also the backlog of ducts that are on our acreage that as we communicate with producers and realign the schedules, we’ll connect those as well. So our future — our 2016 connections will come from the combination of both of those. And we still expect we’ll be in that 250 to 350 range for total connects for the year. Brian Gamble That delta between what we’ve done so far and that midpoint of the range, so call it 185, how should I think about that as far as the buckets are concerned. Just I mean broadly speaking, can you give me a percentage breakdown between the two? Kevin Burdick Broadly speaking, it might be half and half. Brian Gamble Great, that’s helpful. I think that’s it for me. Appreciate it you guys. Terry Spencer Thanks Brian. Operator And we will take our next question from Danilo Juvane with BMO Capital Markets. Danilo Juvane Good morning. Terry Spencer Good morning. Danilo Juvane You guys obviously seeing sort of an increase in your fee-based gathering margins here for the rest of the year. So as you think about guidance for 2016, is the sort of pending issue with the rates in West Texas LPG the only downside risk that you see to this year’s guidance? Terry Spencer You know, as far as West Texas, as I said in my comments, I’m not going to go there for obvious reasons. But you know, as we think about our fee-based activities, we have certainly taken out a lot of risks, okay? And so — and as far as renegotiation of contracts, we’ve been successful at increasing our rates across the board, okay, not just in the NGL space but in the gathering and processing space in particular. So, you know, as we move forward we really don’t see any — we don’t see from a rate standpoint backing up anywhere. Okay? Danilo Juvane Got you. Over the last couple of months, we’ve seen sort of more bullish NGL sentiment in general. How do you guys think about continuing to reach special contracts given that some of the part exposure that you’ve had before sort of is rebounding right now. Is there a percentage that you’re targeting of fee-based versus commodity? Terry Spencer I’ll make a general comment. You know, we don’t have a specific target for any of our businesses in terms of, this is how much fee-based margin we want to have. Obviously, we want to have as much fee-based margin as we can possibly get. And obviously we’re continuing to push on that re-contract and negotiate everywhere we can, certainly bringing new assets and new businesses to the table or new opportunities to the table that are fee-based. When we think about the reduction of risk, we think about it more from a coverage standpoint, okay? What do we need in this business, what do we need in this business segment in order to maintain an appropriate coverage level for each one, and certainly an appropriate coverage level for the entire entity. So that’s kind of how we think about it. Sheridan, do you have anything you want to say about our contracts in NGLs? Sheridan Swords Well, I think the thing that comes out is even in NGL’s we’re continuing to change our optimization exposure into fee-based, and we will continue to do that even in widening the spreads. When we say widening spreads, we think that’s even a better opportunity to start locking in margins. So as you said, we always want to go to more fee-based and take our commodity exposure out. Danilo Juvane Got you. Last question for me. You mentioned coverage being a big reason as how you’re managing some of these contract restructures. Is there a target coverage ratio that you’re looking at long term? Terry Spencer Well, certainly, as we’ve said in the past, you know, at the partnership, 1.1 to 1.15 longer term is a coverage that you know, it could make some sense for us, potentially higher. But certainly as we’ve driven the risk out these businesses, we don’t have to maintain this quite as big a coverage. But that’s kind of how we think about it. Danilo Juvane If you take that statement and sort of think about what you’re thinking about sort of your debt metrics, where do you see yourself being more comfortable starting to bump distributions? Terry Spencer Well, certainly we’ve told you 4.2 times debt to EBITDA ratio is what we’re targeting, but we really would like to be sub-4. I mean, ideally that’s where we’d like to be. And that’s the longer term plan. Danilo Juvane Okay. Thank you. That’s it for me. Thanks. Terry Spencer You bet. Thank you. Operator And we will take our next question from Christine Cho with Barclays. Christine Cho Hi, everyone, congrats on the quarter. Terry Spencer Thank you. Christine Cho When I look at how much ethane is being rejected on your system, the capacity of your NGL pipes and the utilization on those pipes, I have that your pipes are going to be full once all of the ethane behind your system is extracted. Can you talk about the expansion opportunities on the Sterling and Arbuckle line compression or looping? Would you charge a similar rate as you are now? And is it safe to assume that the economics of an expansion, if through compression, is going to be better than the 5 to 7 times multiple you usually give out? Terry Spencer Christine, what I would say is that we feel that we have enough capacity on our existing pipelines to handle the ethane that’s being rejected, but it will push the utilization of those pipelines to pretty high rates. If we get to the opportunity to expand our pipelines, the cheapest expansion is sitting on Sterling 3 and we had said we can take that up 60,000 to 70,000 barrels a day with relatively inexpensive pump stations on there, which would be at a very high multiple to add that kind of space for a very little capital. The other pipelines Arbuckle and the other two Sterling pipelines are fairly expanded with cheap expansion. It would be inter-looping, so it still would be much cheaper than laying a new line but it would be more expensive than what Sterling 3 has. But we think right now we can handle all the ethane that could potentially come out of our system. Christine Cho Okay, and then just piggyback on that, I mean, I have that ethane demand that’s going to be 800,000 barrels per day if we include the ethane export projects along with the cracker additions. Obviously, we’ve been thinking that in the near- and medium-term ethane price is going to go up to equate methane equivalent plus CNF. But do you think over the longer term, we could be short ethane, this would imply that ethane price could approach naptha prices? Terry Spencer Christine, I think what would happen is that first thing if ethane prices increase, you’re going to run into the other LPGs that can be cracked, especially in the existing cracker. So you’re going to hit into propane, butane, and natural gasoline before you get to naptha. So I don’t think we’ll see in the long term ethane prices approach naptha prices. I think propane and other ones will put a lid on the price of ethane. Christine Cho Okay. And then last one for me, very helpful, thank you. What’s the average contract life on the NGL pipelines? And you’ve kind of mentioned this before, but I’m assuming that you have less optimization capacity than you did kind of at the peak, but as these contracts with customers come due, how should we think about how you guys decide whether or not to extend the contracts versus not renew it and maybe retain some capacity for optimization opportunities? Are you kind of happy with the levels that you have now or you want to decrease it, increase it? Terry Spencer Christine, what I would say is that these contracts that you’re referring are contracts that we have with the processing plants. So it’s a bundled service for not just transporting product to Belvieu but also for fractionating it as well. So what we would want to do is always continue to extend those contracts. And if we can get the right prices to take them into Belvieu, we would rather put them on a fee-based business than be open up to the spread between Conway and Belvieu. So if we could, we would contract the whole pipe if we could get it at good rates. Christine Cho Would you say that the bundled rate probably has room to come up then? Terry Spencer Potentially yes. Christine Cho Okay, and one more… Terry Spencer We would… Christine Cho Go on, sorry. Terry Spencer Any time we look at the rates when we go out and look at a plant, we look at what the competition is, we look at how are our services that we provide and all that and try to price our services accordingly. So as prices continue improving going into Belvieu, I think there is some opportunity to increase our rates into Belvieu. Christine Cho And what’s the average contract life? Terry Spencer Most of our contracts, substantial amount of our contracts do not expire until we get into the 2020’s. We do have a little bit that expires between now and then, but most of it is in the 2020’s. Christine Cho Okay, great. Thank you. Terry Spencer Thank you. Operator [Operator Instructions] We will take our next question from Craig Shere with Tuohy Brothers. Please proceed. Craig Shere Good morning. Congratulations on another good quarter. Terry Spencer Thanks, Craig. Craig Shere So I think you said 115 well hook-ups in the quarter, Terry. But guidance I think is still only 250 to 350 for the full year. And if I’m not mistaken one of your major customers has just added a frac crew on a farm to work done, that’s duct inventory. Given all this, is your reiterated guidance for well hook-ups perhaps conservative? Kevin Burdick Craig, this is Kevin. I don’t know if I’d use the word conservative but yes, we’ve had a strong showing out of it for the first quarter. But then again, rigs have dropped off quite a bit as well during that same timeframe. So we continue to talk with our customers daily and understand as commodity price moves around, kind of their sentiment towards either adding frac crews or adding rigs changes a little bit. But right now, we feel good about that 250 to 350. If we have some more movement with producers that are going to accelerate completions in the Williston and then yes, that number could go up. Craig Shere And on the remaining 70 million to 80 million a day of flaring on your Bakken footprint, any thoughts on maybe a run rate as we exit the year? Obviously, new well hook-ups will contribute to potentially some incremental flaring. So this isn’t going to go down to zero. Any thoughts on where we could exit the year? And also over time, are we perhaps seeing the actual amount of flaring that’s reported perhaps be on the conservative side so that you could get most likely higher uplift? Terry Spencer So, a couple of things there. One is as we look at our flaring, keep in mind, there is probably 30 to 40 million behind Bear Creek, so when we bring Bear Creek online, we expect that a chunk, approximately half of that will get put out with that — as that plant comes up. As for the other, yes, there will always be some level of flaring that occurs, but we do have quite a bit and we’ve got some head room from both our field infrastructure and processing plants. So as new wells come online, I don’t know that that would contribute much to the flaring. So I do think we expect that number will go down significantly as we move into the back half of the year once the Bear Creek is up. And yes, when you look at the numbers over the last few months, it does appear that some of the reporting has been conservative for overall — for total kind of state-wide flaring. Craig Shere Great. And on the ethane question, in terms of specs, I think I forgot when, it’s some quarters ago, you had a 20,000 barrels a day of recovery to mid downstream Y-grade requirements. At the time I think you mentioned the possibility of that going away with the downstream solution, obviously still plotting margin for you. Could you see that margin opportunity expanding over time as the Y-grade growth out of the region continues? Sheridan Swords Craig, this is Sheridan. The ethane coming out of the Bakken is for purely products specifications that we have downstream. And right now with the ethane we have coming out there now, we are able to manage that situation. As we continue to look forward, we are trying to find the most economical way to extract, to solve this solution in another way, but we’re still looking at that. It’s capital intensive. So we’re still trying to work on with the right solution for that is. In terms of getting more ethane out of the Bakken for uplift there, we see the opportunity is there as increasing ethane prices with the new petrochemical facilities come online is where we think the most opportunity is. Craig Shere Okay, great. And just a little more color around the NGL segment headwinds, including the $10 million decrease in exchange services and $5.6 million in marketing would be helpful. Maybe just more of a discussion about specific spot and about some volumes and about summarization and trends there. Terry Spencer Craig, the marketing was down mainly because we had a warm winter and also we had less volume from our marketing department going into refineries. We have already seen that tick back up as we move into the second quarter. The extreme services were down, it’s because we had spot volume in the fourth quarter, we had a little bit more ethane rejection in the first quarter, and we had a little seasonal or weather effects also in the first quarter. Volumes that have already rebounded as we move into the second quarter and today our volumes on our gathering systems are at or a little bit above 800,000. Craig Shere Great. And last question. Derek, on the favourable comments you had about favourable bidding for your maintenance CapEx and the falling OpEx cost, how much opportunity is there for further improvement in ’16 and could you see these benefits continuing in the ’17 or is it very kind of variable quarter to quarter? Derek Reiners Hey Craig, I’m going to turn it over to Wes Christensen to answer that question. Wes Christensen Yes, Craig. We continue to have contact with our contractors and find as they are looking for work to keep their crews busy, that there’s opportunity there to improve it. We have already captured quite a bit from them through ’15 and ’16 and expect it to continue in the current environment. Craig Shere Great. Thank you very much and congratulations again. Terry Spencer Thanks Craig. Operator And we will take our next question from Becca Followill with US Capital Advisors. Becca Followill Good morning, guys. Terry Spencer Hi Becca. Becca Followill Hi. On processing, guidance for the year is 1.9 to 2 for the year, but the quarter you were more like 1.95, and you talked about volumes being back-end loaded. Is that back-end loaded for NGLs? And you also have new processing coming on in a year or so, help me out with guidance relative to Q1. Terry Spencer So, yes, it is. We do have some back-end loading, in particular in gathering and processing because the Bear Creek plant coming on in the third quarter is going to fetch you there. And you’re going to see some back-end loading a bit on the NGL side as well. Sheridan, you got anything to add. Sheridan Swords Yes, I mean we do have plants coming online, the Bear Creek plant will add more to the NGL gathering. We have another plant in the Mid-Continent that’s coming on. We just had a plant yesterday, start delivering — a new plant start delivering into the West Texas pipeline asset. So here we are still little bit. We should see growth from here forth. Becca Followill But you’re already at the mid point of the guidance? That’s where I’m coming from. Terry Spencer Becca, could you kind of clarify when you say the — we’re at the mid point of the guidance, which? Becca Followill I’m looking at gas process, it was 1.948, I think your guidance was 1.9 to 2. Terry Spencer Okay. So that’s — again, we had a strong Williston volumes and that’s in — you’re referring to the MMBtus and so that’s driving that. The gas being much richer coming out of the Williston, so that’s what you’re seeing there. Our volume profile just at a high level in the Williston is going to be more flattish for the year. So that’s the reason you’re seeing that. Becca Followill But you’re also adding Bear Creek in Q3? Terry Spencer Right and that will open another — again, that’s 40 million a day in cubic feet. So when you’re talking about the total, it’s not going to move — it’ll move it some. But again, volumes between now and then are going to be flattish and then you’ll see a little uptick. And if thing don’t — depending on completions at the end of the year, you could possibly see a minor decline post Bear Creek. Becca Followill Okay. Thank you. Operator And we will go next to Shneur Gershuni with UBS. Shneur Gershuni Hi, good morning, guys. Most of my questions have been asked and answered several times, but I just wanted to just clarify a couple of things and I think you’ve sort of answered it with Becca’s question before. But the results this quarter with respect to volumes, was that what you expected the first quarter to be, is it better or worse? Does it sort of change because you didn’t change your guidance, does that mean that you still think that you’re within your guidance or are you more towards the upper end now versus the lower end? I was just wondering if you can sort of give us some color as to 1Q performance relative to your official plan. Terry Spencer Yes, we came in pretty much as expected. I mean, as you would expect, you got some areas that performed a little better than expected and others that weren’t quite as good. But overall, this first quarter performance is not a surprise to us and it’s certainly consistent with our guidance we provided for the year. Just a bit more specific, in the Williston Basin, we continue to perform extremely well. In the Mid-Continent, we’ve not performed quite as well but when you look at it on the overall basis, particularly for a G&P segment, we are right on plan, right on our guidance. Shneur Gershuni Okay, perfect. A couple more follow-ups. You stated in the past, I think I saw it written as well too, that OKE stands in support of OKS. Do you expect to have to execute on that this year, or it’s just more of a statement at this point in case if needed? Maybe you can sort of discuss that in context with any discussions you’ve had with rating agencies recently and so forth. Derek Reiners Shneur, this is Derek. The OKE cash balances there, really just is a prudency matter. We like having that flexibility. But as we’ve stated before, we don’t have any plans really to issue equity at this point. So we’ll continue to watch it, but no plans at this point. And in terms of rating agencies, I mentioned in my remarks certainly at the partnership we’re committed to the investment-grade credit rating and that allows us some additional comfort should things not turn out exactly the way we would expect. Shneur Gershuni Okay. And then one last question just technical in nature, Roadrunner, what’s the expected ramp this year? Terry Spencer I’ll turn that question over to Phil. Phillip May Could you — did you say ramp? Shneur Gershuni Yes. Phillip May Okay. Yes, it’s first phase is in service as of March, so it is flowing 170 million a day. Second phase is due in service in the second quarter of ’17 and that will ramp up to 570. And then third quarter will follow in 2019 and that’s another 70 million a day. So total 640 million a day. Shneur Gershuni Okay, perfect. All right. Thank you very much guys. Terry Spencer You bet. Thank you. Operator And we will go next to Jeremy Tonet with JPMorgan. Jeremy Tonet Good morning. Terry Spencer Good morning Jeremy. Jeremy Tonet I was just wondering for the NGL gathering, if you could help us think through kind of what leads to the cadence of the ramp over the year. Is that kind of new plants ramping up or is it more on the connection side, or is it more ethane recovery or if you could just help us with that a little bit, that will be great. Terry Spencer Sheridan. Sheridan Swords I think to know that coming out of the first quarter, we always see a little bit of a downturn on our existing plant because of the seasonality in the first quarter. So we ramp up through the year, some of it will be that. But most of it will be from the ramping up of the plants that we connected last year and the new plants that we’re connecting this year. We really don’t expect any incremental — any substantial incremental increase in ethane recovery in 2016 in our guidance numbers. So mainly, it’s going to be from new plant connections. Jeremy Tonet Okay. That’s great. That’s it for me. Thank you. Terry Spencer Thanks, Jeremy. Operator [Operator Instructions] We will go next to John Edwards with Credit Suisse. John Edwards Yes, good morning everybody. Just I wanted to kind of come back to the incremental ethane opportunity little bit, is the basic cadence of realizing the $200 million, is it more or less in line with what you’ve laid out on your slide eight of the deck you provided with the release where you’re showing the expected incremental petrochemical ethane demand? Or is it going to be some other trajectory? Is it more kind of rateably each year the next few years? Help me understand that a little bit better. Sheridan Swords John this is Sheridan. I think the best way to explain it is currently today we supply about a third of the ethane demand in the United States. And as you see that demand increase, as you see on page eight, I think that ratio will stay the same. So of that increased demand, we’ll be able to see about a third of it on our system. John Edwards Okay. So is it proportionate then to the timing that you’ve laid out there or is it some other pace? Sheridan Swords No, I think it’s about proportionate to that timing. John Edwards Okay. That’s really helpful. And then as far as you had made some reference to the potential for improvement to optimization margins, I think your guidance is $0.02. I mean what are the prospects you think for that number actually improving this year and perhaps next year? Terry Spencer Well, I think the spread between Conway and Belvieu will be — move around quite a bit this year, but I don’t think we’ll see any material substantial increase in that spread until you see the ethane come online which will fill up the pipes between Conway and Belvieu and give you an opportunity for wider spread. So probably more better opportunity in ’17. John Edwards Okay, great. My other questions have been answered. Thank you. Operator Okay. Ladies and gentlemen, that concludes today’s question and answer session and also concludes today’s conference. We’d like to thank everyone for their participation. 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Edison International (EIX) Theodore F. Craver, Jr. on Q1 2016 Results – Earnings Call Transcript

Edison International (NYSE: EIX ) Q1 2016 Earnings Call May 02, 2016 4:30 pm ET Executives Allison Bahen – Senior Manager-Investor Relations Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Jim Scilacci – Chief Financial Officer & Executive Vice President Pedro J. Pizarro – President & Director, Southern California Edison Co. Adam S. Umanoff – Executive Vice President & General Counsel Maria C. Rigatti – Chief Financial Officer & Senior Vice President, Southern California Edison Co. Analysts Julien Dumoulin-Smith – UBS Securities LLC Greg Gordon – Evercore Group LLC Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Praful Mehta – Citigroup Global Markets, Inc. (Broker) Steve Fleishman – Wolfe Research LLC Michael Lapides – Goldman Sachs & Co. Brian J. Chin – Bank of America Merrill Lynch Ali Agha – SunTrust Robinson Humphrey, Inc. Operator Good afternoon and welcome to the Edison International First Quarter 2016 Financial Teleconference. My name is Maddie, and I will be your operator today. Today’s call is being recorded. I would now like to turn the call over to Ms. Allison Bahen, Senior Manager of Investor Relations. Ms. Bahen, you may begin your conference. Allison Bahen – Senior Manager-Investor Relations Thanks, Maddie, and welcome, everyone. Our speakers today are Chairman and Chief Executive Officer, Ted Craver; and Executive Vice President and Chief Financial Officer, Jim Scilacci. Also here are other members of the management team. Scott Cunningham is not here today, as he is recovering from minor surgery and should be back in the office soon. Materials supporting today’s call are available at www.edisoninvestor.com. These include our Form 10-Q, Ted’s and Jim’s prepared remarks, and the presentation that accompanies Jim’s comments. Tomorrow afternoon, we will distribute our regular business update presentation. During this call, we will make forward-looking statements about the future outlook for Edison International and its subsidiaries. Actual results could differ materially from current expectation. Important factors that could cause different results are set forth in our SEC filings. Please read these carefully. The presentation includes certain outlook assumptions, as well as reconciliations of non-GAAP measures to the nearest GAAP measure. During Q&A, please limit yourself to one question and one follow-up. I will now turn the call over to Ted. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Thank you, Allie, and good afternoon, everyone. Our first quarter core earnings were $0.82 per share, $0.08 per share lower than last year’s first quarter. Most of this decline was due to timing differences at SCE during 2015, which were caused by the delay in receiving the 2015 to 2017 General Rate Case. The underlying earnings in the first quarter of 2016 are consistent with the profile we expect for the year. Therefore, today we are reaffirming our 2016 core earnings guidance of $3.81 to $4.01 per share. Jim will elaborate on all of this in his remarks. I will focus most of my comments today on SCE’s long-term growth potential. This is particularly relevant as we prepare for our 2018 to 2020 General Rate Case filing in September, and as the dialogue continues before the CPUC on the Distribution Resources Plan and related proceedings. We believe that there is good visibility to long-term sustained investment of at least $4 billion annually. They should in turn yield rate base growth of approximately $2 billion a year. We have confidence in these levels of investment for several complementary reasons. First, our strategy is very much aligned with California’s goals of creating a low carbon economy and providing customers with energy technology choices. Second, we see several different infrastructure areas that require years of continued investment, all of which can be expanded further from today’s levels and can be flexibly substituted for each other. Third, we have been steadily improving our ability to control overheads and fuel and purchased power costs in order to keep customer rate increases low, even with higher capital expenditures. And finally, as our rate base continues to grow, higher levels of investment can be more easily digested without stressing equity levels or our ability to execute the work. I will expand on each of these points further. As we look at the potential investments on the horizon, they support, and are supported by, several critical public policy initiatives. The overarching policy support comes from California’s desire to create a vibrant low carbon economy. This is not solely a goal of policymakers, but rooted in strong public support across income and ethnic divides. It is well understood that the state’s low carbon goals cannot be met without substantially greater electrification of stationary and mobile sources of energy use. Decarbonization is supported by California’s existing carbon cap-and-trade system, which does not rely on U.S. EPA’s new carbon rules to be implemented. There is also strong support for clean energy technology development in the state, driven in part by the importance of Silicon Valley to the state’s economy and its political influence. Importantly, Edison supplies the critical electric infrastructure investment needed to meet the state’s low carbon goals and facilitate customer choice of new clean energy technology. Let me discuss the areas of infrastructure investment needed to meet the goals of providing safe, reliable and low-emitting power to our customers. Starting with the basics, reliability of the core electric infrastructure requires routine replacement of ageing poles, transformers, underground cable and so on. Our system grew rapidly after World War II through the 1970s. Therefore, many components are reaching their mean time to failure and must be replaced. SCE’s infrastructure replacement program alone represents more than half of our total distribution system capital expenditures. To give you an idea of the size of this task, each year we replace on average 24,000 distribution poles, 4,000 transmission poles, 500 miles of underground cable, and 225 substation circuit breakers. Complementing basic infrastructure replacement is the need to adapt our power grid to changing customer preferences and to new technologies. This evolution to a technologically advanced electric delivery system was outlined in the Distribution Resources Plan, or DRP, that SCE filed last summer. Many of these potential investments are incremental to the investments that make up our current $4 billion annual CapEx. This vision for modernizing the grid will be an important principle as SCE develops its upcoming General Rate Case filing. The CPUC’s regulatory proceedings on distributed energy resources are still in the early stages. Initial insights from the proceeding appear to endorse some of the approaches we recommended in our DRP filing, while suggesting different approaches in other areas. SCE’s General Rate Case filing will be made well before the CPUC has made its full recommendations in the DRP and related proceedings. As a result, SCE will be making its best judgments on the scope and approach to grid modernization in its GRC filing. During the general rate case proceeding, SCE’s views will be synchronized with those of other stakeholders, informed by the discussions taking place in the CPUC’s broader Distribution Resources Plan proceedings. The GRC will be the cornerstone proceeding for determining SCE’s distribution system investment program. However, there are several complementary initiatives that represent additional investment in the power grid of the future, and that are not part of the current $4 billion annual CapEx. The first is electric vehicle charging. Last month, the CPUC officially authorized SCE to commence spending under the Charge Ready pilot program they previously approved. The pilot covers the first 1,500 stations of an eventual plan for 30,000 charging systems. The total program is estimated to provide roughly one-third of the charging infrastructure needed in SCE’s service territory for autos and light-duty vehicles at multi-family dwellings and public locations. While the rate base opportunity for the full program is approximately $225 million over several years, it is possible that the CPUC will consider higher levels of utility investment in charging infrastructure. Longer term, we think it is likely that additional opportunities for vehicle charging and other infrastructure may result from the transportation electrification initiative included in Senate Bill 350, signed into law last year. The bill is better known for establishing the mandate for electric utilities to deliver 50% of their customer load from renewable resources by 2030. But it also expanded the potential scope and scale of transportation electrification, which could support investments beyond SCE’s current Charge Ready light-duty vehicle initiative. The objective is to support California meeting its long-term carbon reduction targets and federal Clean Air Act standards. The electric sector in California, especially the three investor-owned utilities, have become very low carbon-emitting, while the transportation sector has not. The result is that today nearly 40% of total carbon emissions in the state comes from the transportation sector, compared to less than 20% for the electric sector. As part of the implementation of SB 350, this fall the CPUC is expected to order investor-owned electric power companies to submit proposals for investments and programs that will accelerate widespread adoption of transportation electrification. This would include potentially higher levels of light-duty vehicle charging infrastructure than SCE’s current target of providing 30,000 chargers. It could also include charging infrastructure for medium-duty and heavy-duty vehicles such as electric buses, trucks and tractors, which are especially important in meeting increasingly stringent air quality requirements in the LA Basin. These early concepts were part of the agenda at a CPUC workshop in San Francisco last Friday, hosted by assigned Commissioner Peterman. Another potential investment class not included in our $4 billion annual CapEx is the CPUC’s energy storage initiative. SCE has the opportunity to build half of its required 580 megawatts of energy storage and place it in its rate base by 2024. We have yet to attempt to estimate the potential capital spending, rate base or timing of this investment. However, storage is a mandated program and could be significant. The DRP process may spell out a greater role for storage solutions located in the distribution systems as the economics improve and the carbon-reduction attributes of storage relative to gas-fired generation become more apparent. Transmission investments remain an important complement to SCE’s distribution system investment program, though the planning process and scale are quite different. SCE continues to implement three major California ISO-approved investments. These projects are needed for transmission reliability and support the State’s renewable portfolio mandate. On April 11, SCE received a proposed decision to approve the $1.1 billion West of Devers project recommended by SCE and the California ISO. You may recall that we informed you last November of delays in the regulatory approvals of this project due to consideration of an alternative, staged-project. The proposed decision largely adopts the project as we originally proposed. It could be approved as early as May 12. Assuming the PD is adopted by the Commission, and once the required federal approvals are received, the project will be ready to begin construction. The West of Devers project will help California meet its 50% renewables portfolio standard. California ISO is in the early stages of planning for the transmission infrastructure to meet the expanded renewables requirement. This will be integrated with efforts underway to extend the span of the ISO to include adjacent electric power companies in other states. There is likely to be a continuing debate about whether the future resource mix should favor more utility-scale renewables with expanded transmission capacity or distributed resources enabled by an advanced distribution system. I expect it will be a mix of the two models. SCE is positioned to participate in both models. We expect either approach will expand the investment opportunity at SCE beyond the current $4 billion annual level. While it is difficult to predict the exact trajectory of investment levels required to support California’s policy objectives, our general belief is that investment levels could potentially grow beyond current CapEx levels. A critical objective that we and the CPUC share is to avoid causing customer rates from becoming unaffordable due to this expanded infrastructure investment. Our objective has been to keep customer rate increases at or below the rate of inflation in our service territory. To date, our record of accomplishing this goal is quite good. The compound annual growth rate of SCE’s System Average Rate has consistently stayed below that of the Consumer Price Index for our service territory. This is true, whether you look at the last five years, 10 years, 15 years or even the last 20 years. It is especially notable that this has occurred when kilowatt hour usage since 2007 has been flat to declining. Indeed, our System Average Rate in 2016 has dropped 8% from 2015 levels. Importantly, customers react mostly to their monthly bill, not kilowatt hour rates. And our average monthly residential electric bill last year was $94, meaningfully below the national average of $127 a month. We have accomplished this through a sharp focus on reducing overhead costs, creating efficiencies, and due to the benefits of the SONGS Settlement as well as declines in fuel costs. A concluding thought on keeping rates affordable longer term; I believe the growing percentage of the renewables in our generation mix is creating an excellent hedge against the potential future spikes in natural gas prices. Although I don’t expect much upward pressure on natural gas prices in the near to intermediate term, it is difficult to imagine much room for prices to go lower. SCE’s generation mix will move up from the current level of roughly 25% renewables to 50%. The cost of renewables new-build is increasingly becoming equal to or better than natural gas new-build. Also, since renewables have no fuel cost, customer rates are increasingly less exposed to future natural gas price spikes. All of this helps to keep our rate increases modest and electricity affordable, while we increase our investment in building an advanced electric delivery system. As I’ve discussed, SCE has several potential areas of incremental investment, which gives us flexibility to ramp up one program if another starts to lag. This, along with the steadily expanding rate base, earnings and cash flow, allows us to maintain a reasonable and growing total investment program without creating pressure to issue equity or having customer rates rise beyond inflation rates. A balanced program like this should also allow us to continue to provide higher-than-industry-average growth in earnings and dividends. I’d like to conclude with a brief discussion of power grid reliability this summer in the wake of the Aliso Canyon shutdown. SCE is working closely with California regulators and Sempra’s Southern California Gas Company on impacts from potential delays in returning the Aliso Canyon gas storage facility to use. Aliso Canyon provides pipeline pressure balancing to the Los Angeles Basin year-round. It also provides additional supplies in the winter when heating needs increase demand beyond the capability of interstate pipeline deliveries. SCE is one of SoCal Gas’ largest customers and very focused on this issue. Because of the shutdown, the risk to electric reliability has increased, which presents its own public safety implications. As we see it, the best scenario for electric reliability is to expeditiously complete inspections of a few of the more important wells to determine if they could be safely returned to service in time for summer peak power use. SCE is also working on contingency plans to reduce demand and maximize generation flexibility. At the CPUC’s direction, SCE has requested a memorandum account to track any unusual costs related to Aliso Canyon. These include costs related to demand response, energy efficiency, power contracts, et cetera. These costs are not expected to be sizeable. Any extra customer costs related to inefficient power plant dispatch will be captured as part of the ERRA balancing account mechanism. Although this situation shouldn’t create financial risks for SCE, it is a potential reliability issue for our customers. Okay. That’s it for me. I’ll now turn it over to Jim for his financial report. Jim Scilacci – Chief Financial Officer & Executive Vice President Okay. Thanks, Ted. Please turn to page two of the presentation. As Ted indicated, today we are reaffirming our core earnings guidance. I want to emphasize the quarterly earnings profile will be difficult to model given two primary factors; SCE’s delay in receiving its 2015 GRC decision and because revenues are generally weighted towards the third quarter of the year. As discussed when we introduced our 2016 earnings guidance, the simplified rate base approach is the best way to think about SCE’s earnings power on an annual basis. SCE’s rate base is growing, and this implies increasing earnings. However, anticipated revenue increases from both the CPUC and FERC were masked by the timing of revenues recognized in 2015. You will recall that until SCE received its 2015 GRC proposed decision, revenues were largely based on 2014 authorized levels. SCE recorded a significant year-to-date revenue adjustment in the third quarter of 2015 and a large regulatory asset write-off in the fourth quarter in connection with the final decision. With that in mind, let’s look at SCE’s earnings drivers. To simplify the earnings explanation, we removed the impact of San Onofre and tax repair and pole loading deductions. On a GAAP basis, as shown in the 10-Q, revenues are down $41 million, which is equivalent to $0.08 per share. As explained in footnote four, the 2016 revenue reduction relates to incremental tax repair and cost of removal deductions for the pole loading program in excess of levels authorized in the 2015 GRC. As we have previously explained, the GRC decision established balancing accounts to track forecast differences compared to actuals. Importantly, with these balancing accounts, there is no impact on earnings. Lastly, this is also the main driver for the low effective income tax rate for the quarter. After the adjustments, revenues are a net $0.04 per share positive contribution on a quarter-over-quarter basis. Breaking revenues down, there is an $0.08 per share GRC attrition mechanism increase. This mechanism provides for increases in revenues after the 2015 test year. Largely, offsetting this is a $0.06 per share timing issue on the GRC decision. As I mentioned earlier, reductions in authorized revenues from the GRC decisions are not reflected in the first quarter or second quarter 2015 results and were adjusted in the third quarter with the proposed decision and then again in the fourth quarter with the final GRC decision. Finish up on revenues, FERC revenues are $0.02 per share higher, largely for higher depreciation expense. This nets to a positive $0.04 per share earnings contribution from revenues. Moving to O&M, costs are $0.04 per share higher than last year. A significant factor in this was planned El Niño preparation costs, where SCE staged equipment such as portable generators in areas that could be sensitive to storm-related outages, as well as costs associated with responses to storms. While the Southern California El Niño phenomenon did not materialize at the level that had been predicted by many, we did see more significant storm activity than we experienced in 2015. Other important items include planned higher costs for distribution system inspections as well as higher severance costs resulting from ongoing efforts to drive increased productivity and efficiency. Higher depreciation of $0.02 per share reflects the normal trend supporting SCE’s wires-focused capital spending program. Income taxes, excluding the tax balancing account related items I’ve already discussed, are $0.02 per share higher than last year. The effective tax rate in the quarter is 14% compared to 24% last year. As I said previously, the lower rate largely reflects the incremental tax benefits above authorized levels. Excluding the $0.13 per share incremental tax benefits, the effective tax rate would have been 34%. Turning to Edison International earnings drivers, overall costs are higher by $0.03 per share. Holding company costs are comparable to last year. We had no affordable housing earnings this year, since the portfolio was sold last December, while in Q1 of 2015 we recorded $0.01 per share of earnings. Edison Energy’s net loss is $0.02 per share higher than last year. This reflects expected development and operating costs of Edison Energy’s businesses and timing of revenues from the newly acquired businesses. Revenues are $6 million in the first quarter of 2016. Our reported sales from last year were $3 million and only included SoCore Energy and not the recently acquired companies. I’d also like to remind investors that our financing strategy for SoCore Energy’s commercial solar program primarily uses third-party tax equity and project financing. As a result, a portion of project economics go to the tax equity investors. Holding company results on a core basis exclude earnings related to the hypothetical liquidation at book value accounting method for SoCore Energy’s tax equity financings. This is $0.01 per share this year versus $0.02 per share last year. So overall, Edison International core earnings are down $0.08 per share. Please turn to page three. SCE’s capital spending forecast is unchanged from our last call. First quarter and actual SCE’s spending of $1 billion is consistent with 2016 authorized levels. Keep in mind that this forecast does not include any DRP-related spending. SCE will continue to evaluate whether to pursue any early stage work this year. Page four shows SCE’s rate base forecast, which is also unchanged. Please turn to page five. The West of Devers project Ted mentioned is one of the two large transmission projects where most of the investment will be on the current rate base guidance period. Some of you may have followed this proceeding, and there’s one unique aspect to the project. Some of the West of Devers route transits the Morongo Indian reservation in the Coachella Valley. As discussed in our 10-K, a Morongo transmission entity has an option to invest $400 million or up to one half of the $1.1 billion project at commercial operation, which SCE expects to be in 2021. For internal planning purposes, SCE assumes that the option will be exercised. The 2018 GRC will include capital expenditures through 2020. With the option exercise date falling just outside of the period of time we will be providing more visibility on, we thought it was important to bring this option to the attention of investors and analysts. Please turn to page six. We have reaffirmed our core earnings guidance for the full year at $3.81 per share to $4.01 per share and updated our GAAP guidance for first-quarter non-core items. Our key assumptions are also unchanged. That’s it for me. Operator, let’s get started with the Q&A. Question-and-Answer Session Operator Thank you. Our first question is coming from Michael Weinstein of UBS. Your line is now open. Julien Dumoulin-Smith – UBS Securities LLC Hey, it’s Julien here. Jim Scilacci – Chief Financial Officer & Executive Vice President Hi, Julien. It’s Jim. Julien Dumoulin-Smith – UBS Securities LLC Hey, Jim. So, first question, you talked about SB 350 on the call just now. Can you elaborate how the regulatory schedule would jibe with what you’ve already underway on the 30,000 EV deployment? And kind of when you think about the scale of deployment contemplated and the ability to own it, I mean what kind of opportunity is that relative to even just the $225 million (30:37) elaborated? Jim Scilacci – Chief Financial Officer & Executive Vice President So, Julien, I’m going to turn that over to Pedro Pizarro. Pedro J. Pizarro – President & Director, Southern California Edison Co. Hi, there. So, starting with the charge rating piece, I think Jim and Ted had mentioned already we now have approval for the pilot phase, that’s the first 1,500 chargers’ worth. And as soon as we get to the pilot phase, we’ll go back to the PUC with a report and have that proceeded and seek authorization to take on the balance of the up to 30,000 chargers covered by the Charge Ready program. And I think we’ll have visibility into that, and in terms of the regulatory timeline for that, I think it’s envisioned that the pilot might take up to 12 months, we will go to the PUC as soon as we have enough data from the pilot. And tough to forecast how long it might take the PUC to provide approval for the balance of the Charge Ready Program, but we will be going back as soon as we have pilot data. Separate from that, in terms of additional opportunities, I think in Ted’s remarks he commented how it is possible that the PUC might envision a further role for us; I think, a couple directions for that. One could be that with the Charge Ready program, we’ve estimated those 30,000 chargers would cover about a third of the need for charging infrastructure to meet the state’s objectives for electric vehicle deployment. So one potential thrust would be whether the PUC might support us going even further than the Charge Ready program. They want to – don’t have any forecast or anything like that there but that is one potential direction. The other one is SB 350, there is talk about support for a broader utility role in transportation electrification and that could go beyond light-duty vehicles, that could go to other forms of transportation. Again tough to put our arms around what that could be, it will intersect with the integrated resource plan proceeding that’s also called for by SB 350 that’s just undergoing, scoping at the PUC now. So while we can’t point precisely to a specific program or specific number side of it, I think the theme is that there is a general recognition in the state that transportation electrification, whether light-duty vehicles or heavier transport, it’s going to be a big part of achieving greenhouse gas targets and it’s likely there’s some possibility for further utility roles there. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Julien, this is Ted, maybe just one other thing to add in there is as I mentioned, this fall, the PUC is expected order the investor-owned utilities to submit proposals for investments and programs related to the transportation electrification initiative in SB 350. So I think we’ll have a little bit more visibility late this year as to at least what the initial thinking is from the PUC. Jim Scilacci – Chief Financial Officer & Executive Vice President Hey, Julien, this is Jim. Just to finalize the point, when we file the General Rate Case later this year, we’ll include in our forecast of capital expenditures an estimate of spending for electric vehicles and we are developing that now based on what we are seeing in the pilot. We’ll have to come up with an estimate that covers beyond – through all the way through 2020. And we will include that as part of our normal expenditures. Julien Dumoulin-Smith – UBS Securities LLC Including the 350 piece, the SB 350 piece? Jim Scilacci – Chief Financial Officer & Executive Vice President Yes. Julien Dumoulin-Smith – UBS Securities LLC Got it. And then, Jim, just actually a quick subsequent follow-up from our prior conversations, MHI arbitration, just timing expectations, if you can just give us the latest. Jim Scilacci – Chief Financial Officer & Executive Vice President Well, we’ll let Adam Umanoff, our General Counsel, have that fun one. Adam S. Umanoff – Executive Vice President & General Counsel Thank you, Jim. As you know, we operate under a confidentiality order issued by the International Arbitration Tribunal. What we can tell you is that we’ve conducted a hearing, the hearing has ended at the end of last week, April 29, and we are expecting a ruling from the tribunal by the end of this year. It’s possible it could go over into early 2017, but our current expectation is by the end of this year. Julien Dumoulin-Smith – UBS Securities LLC Is there something beyond the current hearing that needs to happen and to get a ruling? Adam S. Umanoff – Executive Vice President & General Counsel There is the usual post-hearing exchange of briefs and then consideration by the tribunal. We’re not expecting any further testimony or any further proceedings in the hearing itself. Julien Dumoulin-Smith – UBS Securities LLC Great. Thank you, guys. Jim Scilacci – Chief Financial Officer & Executive Vice President Thanks, Julien. Operator Our next question is coming from Greg Gordon of Evercore ISI. Your line is now open. Greg Gordon – Evercore Group LLC Thanks, guys. Just a simple question. When you quote that $2 billion notional sort of rate base growth number, obviously that’s before some of the other things you discussed. Does that contemplate bonus depreciation, is that pre bonus deprecation? Is that sort of in the range of what you get with or without – can you be a little more specific? Jim Scilacci – Chief Financial Officer & Executive Vice President Greg, it’s Jim. I think it’s just meant to be a general guideline that, if you’re going to spend $4 billion in capital, the way our depreciation works and roughly the way the closings work out that you get to a rough order of magnitude of the $2 billion in growth in rate base a year. And if you look back in time, rate base, it bounces around from year to year, it could be – if you have a large transmission closing or something that can make that growth be somewhat different, but as we kind of look at the numbers and look at it over a period of time, it seems to work. Greg Gordon – Evercore Group LLC And you’ve had bonus depreciation in one form or another through most of that period, so… Jim Scilacci – Chief Financial Officer & Executive Vice President We have, we have. Greg Gordon – Evercore Group LLC So, that would presume that it’s kind of in there. Jim Scilacci – Chief Financial Officer & Executive Vice President Yeah. And again, it may change a little bit as we go forward in time, because bonus will start ramping down as we get beyond the next couple of years. Greg Gordon – Evercore Group LLC Well, supposedly. Jim Scilacci – Chief Financial Officer & Executive Vice President Yeah. Agreed. Greg Gordon – Evercore Group LLC Okay. Thank you, guys. Jim Scilacci – Chief Financial Officer & Executive Vice President Okay. Operator Our next question is coming from Jonathan Arnold of Deutsche Bank. Your line is now open. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Well, good afternoon, guys. Jim Scilacci – Chief Financial Officer & Executive Vice President Hi, Jonathan. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. A quick question on the parent EIX level drag and the $0.06 in the quarter. I think some of your description as to variance versus last year was helpful, so thanks for that but is $0.06 kind of the current run rate, and if so how do we bridge to the $0.18 for the full year? Is there other things going on or is that just kind of ramp up of the revenues in some of the acquired businesses that get you there and some front ending of costs, so just curious. Jim Scilacci – Chief Financial Officer & Executive Vice President Yeah. So, John – and we’ve reaffirmed the annual guidance numbers. And so we’re going to stick with that, and you could see some variation quarter-to-quarter, it’s really hard to predict especially when you buy some new businesses and costs that float into the first quarter, but we’re going to hold on to what we’ve indicated the – in guidance, the full year impact’s going to be. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Okay. So, but those, you can’t kind of talk us through how you – how the $0.06 in the first quarter kind of becomes $0.18 for the year, or is that just seasonality? Jim Scilacci – Chief Financial Officer & Executive Vice President I think that’s our best plan right now from what we’re seeing. And I don’t have any further commentary in terms of how it’s going to change quarter-to-quarter, but we think the level we indicated at the beginning of the year was appropriate. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Great. Okay. And then just on the Morongo issue that you highlighted, Jim, can you explain the numbers, it’s a $1.1 billion project and you said that they could invest $400 million for up to half of it? Jim Scilacci – Chief Financial Officer & Executive Vice President Yes. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. How does that make sense? Jim Scilacci – Chief Financial Officer & Executive Vice President Well, that’s the way the agreement reads. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Okay. Jim Scilacci – Chief Financial Officer & Executive Vice President So, I think it was – as over time the size of the project is going up, but that’s the way the agreement reads and we’ve assumed that they would exercise for the 50%, but that’s for planning purposes, that’s an option on their side. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. They would end up with 50% of the project and you would receive $400 million, is that… Jim Scilacci – Chief Financial Officer & Executive Vice President No. No. So, if it’s $1 billion, say if it’s $1 billion and a 50% then they could take up to $0.5 billion. So if it’s $1.1 billion then you’ve got the $550 million. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Okay. So it’s the amount would be dependent on what the cost actually is? Jim Scilacci – Chief Financial Officer & Executive Vice President Yeah. So, they have the option. So that’s why we’re trying to describe the full amount. They may only take $400 million for whatever reason. But if it’s a good project, you would expect them to take more. Jonathan Philip Arnold – Deutsche Bank Securities, Inc. Okay. Great. Thank you. Jim Scilacci – Chief Financial Officer & Executive Vice President All right. Operator Our next question is coming from Praful Mehta of Citigroup. Your line is now open. Praful Mehta – Citigroup Global Markets, Inc. (Broker) Thank you. Hi, guys. Jim Scilacci – Chief Financial Officer & Executive Vice President Hi. Praful Mehta – Citigroup Global Markets, Inc. (Broker) Quick question on the vehicle charging. As that program gets built out, how do you see that impacting load and do you have resources right now or what kind of generation mix do you think kind of supports that build-out, given it’s going to be sizeable over time? Pedro J. Pizarro – President & Director, Southern California Edison Co. On electric vehicle charging. Jim Scilacci – Chief Financial Officer & Executive Vice President Okay, I missed the first part. Pedro J. Pizarro – President & Director, Southern California Edison Co. I can… Jim Scilacci – Chief Financial Officer & Executive Vice President Pedro, go right ahead. Pedro J. Pizarro – President & Director, Southern California Edison Co. Sure. I think if you look at electric vehicle charging, to date, it has – we’ve been able to accommodate the number of vehicles that have come on the grid without any undue impact on the system. I think this is one of these items where we’d expect to have planning visibility into what the needs are as the market continues to grow. So, I don’t think it’s one that lends itself to a dramatic spike. I’d also point out that from a system perspective, the Californian system overall still enjoys some pretty healthy resource margins. And then – so I’d expect that certainly over the next several years should be the ability to accommodate that. And then the final point I’d make is that, as the load from electric vehicles increases, that is happening in the context still of the net load for the system, which we continue to see moving in a generally flat to even potential decline as we have other offsetting factors, increased energy efficiency, increased demand response. So, we’ll have to continue to watch this from a planning perspective, as the market develops. But today we’re not seeing any undue impact that would be difficult to manage. Maybe one last little coda on that is that as we get more vehicles on the system, we’re going to be working with the regulators to have the right sort of signals and incentives to encourage charging when it helps from an overall system perspective. So, you guys are all pretty familiar with the concept of the duck curve, the fact that we have a lot more solar on the system today, and the ISO expects that to grow so the extent to which we can accommodate electric vehicles with current resources will be assisted by having charging align better with time periods during the day when we have more energy flowing out of solar panels. Praful Mehta – Citigroup Global Markets, Inc. (Broker) Okay. That’s very helpful. Thank you. And then finally just to link with that, the focus on keeping rates at inflation, going at inflation or below, how does this charging stations, where people are charging at homes, do you ever see that becoming a problem in terms of rate, especially if you say, bonus depreciation, reverses in stocks adding to rate base, start having these kind of charging stations at home as well. Do you ever see rates becoming a challenge, going out in the future? Jim Scilacci – Chief Financial Officer & Executive Vice President That’s always a – great question. There is a lot of factors that affect our rates and capital expenditures, we’re watching any number of items, you’re watching what’s happening with fuel and purchase power. I mean, we’re watching our sales, obviously that’s where you’re getting at, I mean obviously electric vehicle charging helps others detract from it. That would be solar roof panel for potentially energy efficiency. So, we’re trying to balance all those factors, and the goal is to try to keep that, the rates in or around the inflation level. And so, I think Ted’s points were real clear that over longer periods of time we’ve had acceleration in capital expenditures and we’ve had lower gas prices and all these different factors over quite a long period of time, and more importantly in the shorter term, the cost focus, the reduction in costs, because O&M obviously reduces rates dollar per dollar where capital is at a smaller percentage. So we’ll continue to monitor it; obviously from year to year you probably – we may exceed it or go underneath it, like this last year was 8% reduction. But over time, I think as the general trend we’d like to see it come in around that inflation level. Praful Mehta – Citigroup Global Markets, Inc. (Broker) Got you. Thanks so much, guys. Jim Scilacci – Chief Financial Officer & Executive Vice President Okay. Operator Our next question is coming from Steve Fleishman of Wolfe. Your line is now open. Steve Fleishman – Wolfe Research LLC Yeah, hi. Ted, can you hear me? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Yes, Steve. Steve Fleishman – Wolfe Research LLC All right. Just, I wanted to maybe just try and summarize your prepared remarks comments on the capital spending. So, you talk about the $4 billion a year of CapEx, and $2 billion of rate base growth, but then when you go through the different segments, a lot of them including some of that the DRP, electric vehicle storage could be kind of upside to that $4 billion a year. And then at the end you talk about maybe some programs could lag over time and the like. And so I’m just overall – are you kind of sending the message that we’re likely to see higher capital spend over this future period than we’ve had in the past, given these variety of new programs? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Yeah. Just, cutting right to the quick, the short answer is yes. Steve Fleishman – Wolfe Research LLC Okay. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer So, the point we’re really trying to make is there are many levers. There is also a balancing act. So, under the many levers part of the equation, if for some reason one or more of these potential capital spends lags or we need to pull it back, there are substitute capital spending that can be pushed into its place. So I think we feel confident about the – certainly feel confident about the $4 billion and believe that there is upside. I’d say the second part is the balancing act element where – you’ve heard me on this a lot of times before – that if you get this thing growing too fast, you end up putting pressure first on customer rates and secondly on the ability of the underlying business to support the equity requirement of the new investment. So it’s a matter of trying to get it in the sweet spot where you’re getting kind of the maximum benefit from the growth but not so fast that it puts pressure on the need to issue equity or on customer rates. And that was the second kind of main point that I was trying to get across here is – as the rate base grows, earnings, cash grow along with it. We feel comfortable about being able to support a greater than $4 billion number without having to issue equity, and secondly, as we tried to spend quite a bit of time on here in the remarks, we actually have a really good track record of keeping customer rates below the rate of inflation in our service territory. And that coupled with the fact our average residential bill is considerably lower than the national average and that’s what customers really see, we feel we’ve kind of got the cost side under control and that it will support the ability to have this expanded investment opportunity. So those are kind of all the main points that I was really trying to make. Steve Fleishman – Wolfe Research LLC No, that’s helpful. And just in terms of the visibility on these longer-term numbers, I know we should hopefully get a lot of that with the GRC filing. And we’ll have the – the DRP spend will likely be within the GRC … Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Yeah. Steve Fleishman – Wolfe Research LLC … filing. But things like the storage and the electric vehicles will kind of continue on their own pace separate from that? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Likely yes. Just a word on the General Rate Case and some of these other proceedings that will be going on at the same time. I think this one is going to be a little different for us in that what we put into the General Rate Case will try to anticipate, at least our best thinking on how we see some of this grid modernization activity taking place. Even though that will be in the process of being discussed coincident with the rate case filing, so that will be in the DRP proceedings. So this is going to be a little bit of – couple of things happening at the same time. We will do our best to articulate those in the General Rate Case. And there are other things, kind of the third point, there are other things above and beyond strictly what’s in the DRP or what you would find in the General Rate Case, and that’s what we are alluding to with some of the transportation electrification initiatives embedded in SB 350 and things of that sort. Storage and other pieces (48:54) would probably largely be outside of that. And of course, as more things develop with the transmission spending, as we look towards moving to 50% renewables and an expanded ISO, California ISO scope, there may very well be other investment opportunities embedded in that that also are not going to be in the GRC or some of these other proceedings. So, I think the general point here is there is, we feel, a robust opportunity, but of course, we want to make sure we’re doing that in a good, balanced way, so, it doesn’t put pressure on equity and doesn’t put pressure on customer rates. Steve Fleishman – Wolfe Research LLC Great. Thank you very much. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer You’re welcome. Operator Our next question is coming from Michael Lapides of Goldman Sachs. Your line is now open. Michael Lapides – Goldman Sachs & Co. Hey guys. I’ll follow on to Steve’s question a little bit, but maybe a slightly different angle. Ted, it seems like you’re hinting that somewhere in the post 2017, you’re going to have CapEx above the $4 billion range. The when and where and how is still to be determined, but you seem pretty confident in that. I guess my question comes to the dividend, which is how are you thinking about the dividend growth trajectory, given the fact that kind of the risk reward to CapEx in the out years is higher rather than lower? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Well, I think that’s kind of embedded in our stated target, which is as you know, lower than what the industry average is. So, we have a 45% to 55% payout ratio target on SCE’s earnings. If I remember it right, the average utility payout ratio is somewhere between 60% and 65%, probably closer to 65%. So, and again, you’ve heard on me on this before, I believe given the growth prospects, the long-term growth prospects at SCE and Edison, that we probably should have a somewhat lower stated target. We’re mindful of the fact that that is lower than the industry average. I’ve probably used the phrase so many times, you guys are sick of hearing about it. But we still believe there is good room to come forward over the next few years here with dividend increases that are above the industry average, as we move up into this 45% to 55% payout ratio. There could potentially be opportunities above that, but we’ll worry about that when we get there. Michael Lapides – Goldman Sachs & Co. Got it. And one follow-up, unrelated, what’s the latest process or procedure wise, at the CPUC, when it comes to the request for re-hearing on the SONGS decisions? Adam S. Umanoff – Executive Vice President & General Counsel This is Adam Umanoff. There really is no additional news we have to share, the challenges to the SONGS OII settlement remain pending at the CPUC and we are awaiting a decision. Michael Lapides – Goldman Sachs & Co. And the CPUC can you just kind of rule any day TBD? Adam S. Umanoff – Executive Vice President & General Counsel Yeah, there is no fixed timeframe for them to rule. It could happen tomorrow, it could happen in six months. We don’t have any guarantees of timing. Michael Lapides – Goldman Sachs & Co. Got it. Thank you, Adam. Much appreciated. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Thanks, Michael. Operator Our next question is coming from Brian Chin of Bank of America. Your line is now open. Brian J. Chin – Bank of America Merrill Lynch Hi. Good morning. Can you hear me? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Hi, Brian. Brian J. Chin – Bank of America Merrill Lynch Hi. Just a general question about net metering policy in California. We’ve seen some interesting developments in New York and it seems like the tone in Arizona has marginally shifted towards a little bit more reconciliation, as opposed to outright conflict. Is there any sort of read-through to the different parties in California in terms of what’s going on in other states, as to how things might play out and might tip the scales in one direction or another in California, just more general thoughts there, if you would. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Want to take that, Pedro? Pedro J. Pizarro – President & Director, Southern California Edison Co. Yeah sure. Hey, Brian. It’s Pedro, how are you? Brian J. Chin – Bank of America Merrill Lynch Good, Pedro. Pedro J. Pizarro – President & Director, Southern California Edison Co. So yeah, we’ve seen with interest the agreement in New York among the utilities and some of the solar parties, and read about the Arizona piece as well. Just stay at a high level here and say that we’ve had constructive discussions with a number of the parties on all sides here in California as well. Obviously we proceeded through the NEM portion, NEM 2.0 proceeding here earlier this year. We did file a limited application for re-hearing on the topic, don’t have a timeline at this point in terms of when the PUC might consider that. But I think at the core – certainly from the utility perspective, we have a strong interest in seeing the market for solar be supported, and we’re doing our part, we want to make sure that our grid is getting continuously worked on to be a more and more of a two-way plug and play grid that can support solar resources. And we’ve done things like work on our own internal processes to shorten the timeframe for customers who want to interconnect on to our system. Used to take us about a month to process applications; we’ve got that down to a day and a half now. So, we’re doing a lot of things that we believe are constructive and supportive, bringing solar online. I think the NEM debate in California and other states has been more about what’s the cost responsibility and the level of subsidy. And so to the extent that parties can come together, and have creative approaches towards resolving some of those differences that’s great. I don’t think we’re there in California today, but we’ll continue to engage constructively with parties, and listen to ideas. Brian J. Chin – Bank of America Merrill Lynch Great. Thanks for the update, Pedro. That’s all I got. Operator Our next question is coming from Ali Agha of SunTrust. Your line is now open. Ali Agha – SunTrust Robinson Humphrey, Inc. Thank you. Ted or Jim, for the last several years now, you guys have done an excellent job of managing your costs and in fact that has allowed you to, in the off years, earn returns above your authorized levels as well. Just wondering how much more is left on that cost reduction side and when you benchmark yourself to where you need to be, are you halfway there, almost there just in the first quartile, can you give us some sense of where you are on that cost reduction plan? Jim Scilacci – Chief Financial Officer & Executive Vice President Hi, Ali, it’s Jim. I’ll straight it out and let Maria and Pedro chime in if I miss anything. There is more work to be done. We started this journey probably four years ago, and we saw at that point in time that, especially in our staffing, our A&G areas that we were considerably above benchmarks. And as you know, we benchmark our costs every single year and we break it down in significant detail in terms of some of the studies that we participate in, and there is more to be done. And it gets harder over time, as you take care of the things that we had -as I said the overstaffing areas that we were able to reduce and we’ve taken care of lot of that but there is more to be done. And for example, we revised our costs in our programs for our healthcare for the employees, and that takes it – over time, it builds up the advantage of that savings and it’s really a cost avoidance for customers, that will then reap that benefit over time. And there is a number of other initiatives there going on. I can’t peg, what you’re asking me, well, how far, you’re halfway, you’re a third of the way, you’ve got two-thirds to go, it’s really hard to say, because it’s really organization-by-organization that we’re looking at theses and some organizations may be in the first quartile, others may be in the fourth quartile. So, you really have to break it down and look at it that way. I’ll pause here and look if Pedro and Maria to add anything. Maria C. Rigatti – Chief Financial Officer & Senior Vice President, Southern California Edison Co. Yeah, we’re going to continue to look at also what our peer group does, because as they get better we’ll find ways to also trying keep pace with what they are doing. Ali Agha – SunTrust Robinson Humphrey, Inc. Okay. And then, second question, I wondered just kind of at your comments on the balancing act that you’re looking at, keeping customer rates at or below inflation. Within that context, equity issuance, just wanted to understand, are you adamant that you’re going to fund all your CapEx going forward, without needing to issue equity, if those – some of those new plans come in and the CapEx goes above $4 billion, but that requires equity issuance. Would you be open to that, or just wanted to understand, is no equity completely necessary for you, over the next several years? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer Yeah. It’s – I mean it’s fair question, but I think without trying to be wibble wobbly about it, the way we see it is we have a significant investment opportunity, we actually think it’s an expanding investment opportunity. Because the rate base is expanding, which means cash production is expanding. But this, as we see it, allows us to keep the growth rate in balance with our retained earnings and existing equity so that we would not need to issue additional equity. Obviously, if the commission or somehow we’re ordered to do something really dramatic, we’re going to maintain our required equity ratio but I think that’s such a remote risk that I feel comfortable saying it the way we’ve said it, that the key here is to keep the growth rate in balance with keeping customer rate increases at or below the rate of inflation. And as we’ve evidenced here, we’ve done, I think, a really great job of that, and we intend to continue to do that. And such that we don’t have to issue equity and I think we can keep that balance. We’ve done it even when we had 12% annual rates of growth in CapEx and earnings; yet, we were able to – so pulling a lot of rabbits out of the hat, we were able to avoid any equity issuance and that was a very strong commitment that Jim and I had all through that period of time. So I feel comfortable making a statement, we’ll keep it in balance. Ali Agha – SunTrust Robinson Humphrey, Inc. And what is the regulatory equity ratio right now for you guys? Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer I missed that. What was the what? Ali Agha – SunTrust Robinson Humphrey, Inc. At the end of this quarter what is the equity ratio at the utility (1:00:15)? Jim Scilacci – Chief Financial Officer & Executive Vice President It’s 50.2%. Ali Agha – SunTrust Robinson Humphrey, Inc. Versus 48% authorized? Jim Scilacci – Chief Financial Officer & Executive Vice President Yes. Ali Agha – SunTrust Robinson Humphrey, Inc. Okay. Thank you. Theodore F. Craver, Jr. – Chairman, President & Chief Executive Officer You’re welcome. Operator That was the last question. I will now turn the call back to Ms. Bahen. Allison Bahen – Senior Manager-Investor Relations Thank you for joining us and please call if you have any follow-up questions. Thanks. Operator That concludes today’s conference. Thank you for your participation. You may disconnect at this time. 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.) 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