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ONEOK’s (OKE) CEO Terry Spencer on Q2 2015 Results – Earnings Call Transcript

ONEOK, Inc. (NYSE: OKE ) Q2 2015 Earnings Conference Call August 05, 2015 11:00 AM ET Executives T.D. Eureste – Manager, Credit and Finance Terry Spencer – President and CEO Derek Reiners – SVP, CFO and Treasurer Kevin Burdick – VP, Natural Gas Gathering and Processing Sheridan Swords – SVP, Natural Gas Liquids, ONEOK Partners Walt Hulse – EVP of Strategic Planning and Corporate Affairs Wes Christensen – SVP, Operations Phil May – VP, Natural Gas Pipelines Analysts Christine Cho – Barclays Capital Chris Sighinolfi – Jefferies & Company Kristina Kazarian – Deutsche Bank Craig Shere – Tuohy Brothers John Edwards – Credit Suisse Michael Blum – Wells Fargo Securities Becca Followill – US Capital Advisors Eric Genco – Citigroup Matt Niblack – HITE Hedge Operator Good day everyone, and welcome to the Second Quarter 2015 ONEOK and ONEOK Partners Earnings Call. Today’s call is being recorded. And at this time, I would like to turn the conference over to Mr. T.D. Eureste. Please go ahead. T.D. Eureste Thank you and welcome to ONEOK and ONEOK Partners’ second quarter 2015 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 many thank you for joining today and for your continued interest in ONEOK and ONEOK Partners. On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, our Chief Financial Officer; Wes Christensen, Senior Vice President, Operations; Sheridan Swords, Senior Vice President, Natural Gas Liquids; Kevin Burdick, Vice President, Natural Gas Gathering and Processing; and Phil May, Vice President, Natural Gas Pipelines. As noted in our second quarter earnings results release yesterday afternoon, key financial and operational information discussed during our first quarter earnings call has been updated in a short presentation and is posted on ONEOK’s and ONEOK Partners’ Web site. Please refer to this presentation and to the earnings releases for various explanation and key metrics. With the information that has already been provided, I intend to keep my remarks brief today and focus on a few key areas. We’ll spend the majority of our time answering your questions. To begin, even in this continued weak commodity price environment, we expect that both ONEOK and ONEOK Partners will end the year within our 2015 financial guidance ranges. And as we exit 2015, we expect 2016 to continue to benefit from the completed and soon to be completed capital growth projects in the natural gas liquids, natural gas pipelines and natural gas gathering and processing segments. We are seeing volume growth through the first half of the year as anticipated, particularly regarding natural gas liquids gathered and fractionated and natural gas gathered and processed. We expect these volume increases to continue into 2016. Overall, the Partnerships’ year-to-date performance positions us to achieve our natural gas gathering volume and financial objectives for the year. I will now turn the call over to Derek for a brief discussion of ONEOK Partners’ and ONEOK’s financials. Derek? Derek Reiners Thank you, Terry. Starting on partnership, 2015 EBITDA contribution continues to ramp up as strong volume growth is shaking up as we anticipated. We expect to grow our EBITDA in the second half of 2015 and be within our 2015 financial guidance EBITDA range of $1.51 billion to $1.73 billion. Our EBITDA growth follows the volume growth. Even in this lower commodity price environment, the Partnership’s year-to-date EBITDA of $712 million is only $40 million less than in the same period in 2014, which was a record in environment with much higher commodity prices. Our coverage ratio has improved to a 0.88 times coverage in the second quarter of 2015 and we expect continued improvement in our coverage the balance of the year. The partnership has a solid balance sheet and ample liquidity to support our current capital program including access to our commercial paper program and credit facility. As of June 30, ONEOK Partners had an adjusted debt-to-EBITDA ratio of 4.5 times. As we said, investment grade credit ratings of ONEOK Partners remain very important to us. Through the first half of 2015 our ATM program was a very effective tool for issuing equity and we continue to evaluate the overnight equity markets and other sources of capital. We will continue to take a balanced approach and remain disciplined when issuing debt and equity. Additional equity is needed to continue to support our capital projects. We continue to remain confident in our ability to raise necessary capital to fund our capital projects at ONEOK Partners. At ONEOK our liquidity remains strong with a $150 million in cash and undrawn $300 million credit facility, and a debt-to-EBITDA ratio of 2 times at June 30. We continue to retain access cash at ONEOK as we navigate these uncertain times. Terry, that concludes my remarks. Terry Spencer Thank you, Derek. Now let’s take a closer look at each of our business segments, starting with our natural gas liquids segment. The segment’s 2015 year-to-date results were supported by solid second quarter performance. The segment’s year-to-date operating income exceeds year-to-date 2014 operating income. This becomes a more useful statistic when you consider that first quarter 2014 results rightly benefited from a historically high demand for propane and that in 2015 the segment has experienced lower realized NGL product price differentials and narrower NGL location price differentials. So even though year-over-year the segment was competing with the 2014 propane benefit, operating income so far in 2015 has exceeded first half 2014 totals because of the continued strong growth of fee based revenues and volumes. Our integrated NGL system continues to benefit from providing non-discretionary fee-based services to NGL producers by connecting growing natural gas liquids supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. The natural gas liquids gathered volume on the Bakken NGL pipeline reached approximately 100,000 barrels per day in July and is expected to reach approximately 105,000 barrels per day in the fourth quarter 2015. This is an increase of approximately 20,000 barrels per day from what we expected in the first quarter as a result of decreased ethane rejection in the Rocky Mountain region. We will talk more about the reduced ethane rejection in a moment. The average bundle gathering and fractionation rate on the Bakken NGL pipeline is more than $0.30 per gallon. Moving to our fractionated volume. In addition to the increased ethane fractionated due to the decreased ethane rejection, we also saw more than 20,000 barrels per day of incremental interruptible volumes on our system in the second quarter as we were able to utilize our fractionation assets to meet market demand. We expect to continue to see approximately that level of incremental interruptible volume from our system into the fourth quarter. As a reminder, we do not include interruptible volumes in our fractionation volume guidance. And finally, in recent weeks, we have seen Conway to Mont Belvieu ethane price differentials range from $0.02 to $0.03 per gallon and we expect this range to continue for the rest of this year. As you know our natural gas pipelines business is primarily fee-based with long-term firm demand charge contracts. We continue to develop new projects and opportunities to grow our fee-based earnings. Just last week we announced plans to expand our ONEOK WesTex Intrastate Natural Gas Pipeline System in the Texas Panhandle and Permian Basin. The expansion which will complement our previously announced Roadrunner Gas Transmission Pipeline joint venture is already 90% subscribed with 25 years firm demand charge agreements. These projects and the expansion of our Mid-Western Gas Transmission Pipeline System are continued examples of our committeemen to stable long-term fee-based earnings growth. The natural gas gathering and processing segment’s second quarter results were significantly improved over the first quarter. Earnings for this segment are still expected to be significantly weighted towards the second half of the year which is in line with the expected growth of our 2015 natural gas gathered and processed volumes. We have greater confidence in our Williston Basin volume projections with six months of operating performance under our belt and good visibility into the remainder of 2015. The segment is seeing the benefit of rigs concentrated in the most productive areas, new well connections, two compressor stations completed, and the current flared gas inventory. We expect Williston Basin volume in the third quarter to reach approximately 650 million cubic feet per day as we continue to bring on additional field infrastructure. Additionally, our new well connections continue to exceed our expectations as we completed nearly as many in the first half of 2015 as we did in the first half of 2014. We remain on track to fill our plans to approximately 685 million cubic feet per day in the fourth quarter as we complete gathering system and compression projects through the second half of the year. These new compressor stations will not only fill our existing plants but also will provide capacity to ramp up volumes at our Lonesome Creek plant, which is expected to be completed late in the fourth quarter 2015. In the Mid-Continent our volumes increased quarter-over-quarter due to incremental interruptible gathering and processing services we provide to third parties from time to time as demand dictates. In addition, a key producer in the Cana-Woodford as expect has now started the process of completing wells drilled in the first half of the year. Our commercial team continues to make progress with customers on its recontracting efforts and has same positive results in increasing our fee based margin while providing enhanced services to our customers. Additionally, we reduced the level of ethane rejection in the Rocky Mountain region in June 2015 to maintain downstream NGL product quality specifications to ensure continued reliable delivery of high quality NGL products to meet the needs of our downstream markets. We expect the decreased level of ethane rejections to continue. Our producer customers are continuing to find ways to reduce drilling cost, and are doing more with less. Said another way, our producer customers are increasing volume with fewer but more efficient rigs and advanced completion technologies are increasing well production rates to levels the industry has never seen before. Our positive operating performance through the first half of the year, combined with what our producer customers are communicating to us, has given us greater confidence in our 2015 natural gas gathering and processing volumes and momentum into 2016. Much like 2015, our 2016 volume growth is expected to be led by growth in the Williston Basin. In the Williston we connected more than 260 new wells in the second quarter 2015, bringing our year-to-date total to more than 560 new well connections. We still expect to reach our 2015 new well connection goal of more than 700 wells and our 2016 goal of more than 600 new wells. That continues to be an inventory of flared gas in the Williston Basin and we estimate approximately 145 million cubic feet per day is dedicated to the Partnership with the majority of the wells flaring already connected to our system. As I touched on earlier, our producer customers are doing more with less. There’re approximately 40 rigs drilling in the most productive areas at any given time on our acreage dedication in Northeast McKenzie, North Dunn and Southern Williams Counties. Additionally wells in the high producing areas continue to exhibit significant performance improvements; producing two to three times more natural gas than lower producing areas. Additionally, more than 900 wells, which have been drilled but not completed, remain in the basin. The continued drilling flared natural gas inventory, improved well performance and significant backlog of uncompleted wells is expected to continue and help contribute to the Partnership reaching its 2016 natural gas gathered volume expectations. Our strong natural gas liquids and natural gas volume growth in the second quarter support the volume outlook we’ve been communicating and provide our stakeholders additional visibility to support our volume growth outlook for the second half of the year; and most importantly, our financial guidance expectations for 2015 and the momentum into 2016. As always, thank you for your continued support in ONEOK and ONEOK Partners and thank you to our dedicated employees for your hard work and continued commitment to our Company. Operator, we’re ready for the questions. Question-and-Answer Session Operator Thank you [Operator Instructions]. And we will take the first question today from Christine Cho with Barclays. Please go ahead. Christine Cho I just wanted to start with the reduced ethane in the Rockies. When you say to maintain downstream product quality specifications, are you talking about meeting natural gas pipeline specs? Terry Spencer No Christine we’re talking about natural liquids specifications…. Christine Cho So…Yes, more color would be helpful. Terry Spencer Sure, and Sheridan, I’ll let you talk about it. Sheridan Swords The NGLs coming out of the Bakken have a high oxygen content, and as we fractionate that oxygen, it’s been driven into the propane, and the butane and to be able to get that by bringing more ethane on, we can driven it into the EP or we can treat it and we continue to make sure that the propane is on spec for delivery into the end use market. Christine Cho And then I guess a molecule [ph] from the Rockies. How much does that generate? I am assuming it’s not the full $0.30 that we usually look at for Bakken. Terry Spencer It is — we are having, it’s close to that number but there is some offset versus that current ship wrecker pays are demand charges that we have. So this is going to offset, it gives demand charges as well. So it’s not the full $0.30. Christine Cho Okay, but not something for off ’15? Terry Spencer It’s close, yes. Christine Cho Okay. I guess one of your competitors is in the process of connecting two of their NGL pipelines that would bring 50,000 barrels per day of propane from the Marcellus into the Midwest. Do you have any thoughts that you could share with us about what that level of supply could potentially use to the spread between Belvieu, Conway. Is that kind of supply going over along Conway or is that already enough excess capacity between Conway and Belvieu that it could easily go to Gulf Coast without any problems or does it just pretty prevent Conway from ever trading at a premium, again like it did last year. Any color would be helpful? Terry Spencer Christine what I would say is that obviously more volume into the Mid-Continent has nothing but improved spreads. We do think there is the ability to move some propane from Conway down to Mont Belvieu, especially if you displaced out a product. So these are all back spot ones that you may move more propane than butane and more propane than the EP or ethane that you have. But we do think there is capacity to move incrementally more volume between the two. But I think it will normally have a widening effect on the spread and it will have a dampening effect on Conway ever trading over Belvieu, you are correct. Christine Cho Okay. And then I guess last question from me. You guys have done a sizable amount of equity on the ATM year-to-date but like you said you are going to have to do more and because I think the market has somewhat of a wide range out there and what that number is, it kind of puts a bigger overhang on OKS. So that’s EBITDA you guys report is always different than what I calculate and I suspect it’s because of the project credit that’s in there but how far does the credit rating agencies go in giving you that credit, is it year, 18 months, two years, any color on how they have used your balance sheet would be helpful? Derek Reiners Sure Christine, this is Derek. On an unadjusted basis, our debt-to-EBITDA has shown a 5.1 and we reported 4.5 on an adjusted basis, you are correct. The principal difference there is the material projects that we have on our way that we receive some credit for in our covenants so that’s that delta. On a run rate basis, you are probably 1 or 2 basis points lower than that if you just took four quarter — or excuse me second quarter and multiply that by 4. The agencies I think give us some credit for that, I am not exactly sure to what extent, they don’t exactly share all their calculations with us. But they certainly understand that as we’re in construction mode, we will be issuing equity and debt for that matter ahead of the realization of the earnings from those projects. And so I think there is some benefit afforded to us in that regard. Cleary agencies look forward and think about the nature of those projects and the earnings from those projects going forward as they think about, how does our leverage looks going forward. Christine Cho Thank you for the color. Derek Reiners You bet. Terry Spencer You bet. Thanks Christine. Operator And we will now go to Chris Sighinolfi with Jefferies. Chris Sighinolfi Hey good morning Terry. Terry Spencer Hey good morning Chris. Chris Sighinolfi Thanks for the added color this morning also thanks to Walt and T. D. for the slide presentation and the added disclosure, it’s very helpful to us. So I just want to say thanks. Terry Spencer You are quite welcome. Chris Sighinolfi Couple of questions, I guess the follow on with where the screen going originally, the slide 4 where you have the volumetric data since the April update, clearly the Bakken NGL volumes are up materially from April end of July and you expected peak rates for the fourth quarter. You mentioned Terry the effects of reduced ethane rejection and interruptible volumes on 2Q and the guidance. But the wondering sort of those factors 2Q with an upside price for you on those fronts. So what are you seeing in the Bakken and I guess what gives you confidence with the forecast and could we see further upside from the products that you mentioned as we move into the back half? Terry Spencer Well Chris I mean we have increased confidence because our producers are performing and we continue to have lots of discussions to get a better understanding of where they are and what their plans are and they are executing those plans and as we said they are continuing to improve their cost structure and improve their technology and really significantly outperformed even in the midst of slight rig reductions in some cases. So we’ve got good visibility into the quarter and that’s the reason why we feel so confident about the volumes. That plays right into the natural gas liquids segment particularly as we produced more natural gas liquids out of the Rocky’s and we produced more natural gas liquids out of the Mid-Continent that benefits the NGL segment. So it’s about visibility, it’s about continued communication with these producers. Chris Sighinolfi And so on the, I guess the downstream spec element, the Sheridan’s comments. Is there further upside on that element, what you saw in Q2 and thus far in 3Q? Or are we fairly comfortable with their specs look like given base level and production volumes on is different? Sheridan Swords Well, one thing I would say is that in 2Q we discovered that we stated the ethane recovery or decreased ethane rejection in June, so you would have a full three months in the third quarter and full three months in the fourth quarter. So we think the level of ethane, or close to the level ethane that we were extracting today, is enough to bring these products into the spec and we can handle and get into the end use market. Chris Sighinolfi Sticking with that slide, slide number four, for a moment, it seems like the steepest projected ramp in July volumes to year end is on the West Texas system. So I just had a couple questions there. First, what is driving the ramp? Two, it looks also like the blended tariff rate on the system maybe came up a penny from the April update. I’m wondering if that was due to any recontracting if I am over-reading or reading too much and it’s something like there is something else going on. And then three, Terry you had mentioned when you bought that asset the potential to fractionate barrels coming off gathering Permian volumes. So just wondering when we might expect to see the approach of that effort or if you could give us something on it? Terry Spencer The first thing I’d say is July is down a little bit, the 2 15 is down a little bit from the fact that we had some outages on the system that caused the volume to be down. Also the reason the $0.04 we’ve gone from $0.03 to $0.04 just because we have increased the tariff rates on the pipeline closer to market than from what it was. So you’re seeing an increase in rates on the existing volume there. We continue to think that we’ll have ramp up there as we talk to more producers out there and we think there is opportunity for that to grow. As you point out that the West Texas pipeline has the lowest margin on our system, so it doesn’t have the biggest impact. Chris Sighinolfi And then on the fractionation side of it longer-term, just give an update on where we stand. Terry Spencer We continue to talk to producers and processors out in the Permian who are looking for a bundled service, not just transportation to fractionation and delivery into the end use market. So as we stated when we bought this pipeline, we think the ability to bring that bundled service to customers of the West Texas pipeline greatly enhance our ability to bring product to the line. And so we are in negotiations with various people on the line to be able to do that. Chris Sighinolfi Sheridan, anything to talk about? Sheridan Swords No, I didn’t have anything to add, Chris. Chris Sighinolfi I guess one final thing on the asset side, it looks like Stateline de-ethanizer was moved out a little bit. Given the comments around reduced ethane rejection, I’m just wondering what drove that and any and that that movement in time would have on cost or return. Kevin Burdick The de-ethanizer was pushed back is regarding to the details of the design and it was really two drivers. One was as we work with our contractor. There was some long lead time equipment that got in and pushed the dates out a little bit. And then as we recast the dates when we apply for winter construction and looked at the efficiency we have when we run our projects through the winter, that cost us some time to — don’t think it will have a material impact on our ’16 what we’re thinking there. Chris Sighinolfi One final thing for me, just, Derek, the 4.5 times debt to EBITDA leverage metric that you quoted, that is consistent with how we interpret the covenants on the credit facilities, is that right? Kevin Burdick Yes, that’s correct. It is exactly the way that we file with our banks for covenant compliance. Chris Sighinolfi Okay, perfect. Thanks a lot for the added color today, guys, and congrats on a great quarter. Kevin Burdick You bet. Thanks Chris. Operator And we’ll go to Kristina Kazarian with Deutsche Bank. Kristina Kazarian Quick follow-up, first on leverage levels, can you talk — I note you guys talked about this a little bit in two of the previous questions. But can you talk a little bit more about what I should be thinking on in terms of where the rating agencies want you guys to go on like a year-end run rate basis to keep an IG rating, and what that would mean for the use of the ATM or maybe even a block, and how you think about that given where the different currencies are trading right now? Derek Reiners The agencies I think have put out some guidance for us in their most recent updates. I think Moody’s talks about a 4.5 times and S&P talks about 4.25 to be in those ranges. So certainly we think about that as we consider our equity needs during the year. We’ve said many times the ATM has been a good tool for us and certainly would expect to continue to use that in the future. But again, we have to kind of balance the balance sheet needs, the leverage with the issuing equity at a higher yield certainly than we would like to see. And of course as to additional you pay distributions on those units and so that impacts your coverage. So it’s a balance and certainly we have regular communications with the agencies and let them know what our plans are. Kristina Kazarian And then bigger picture, I know we often talk about the desire to move more from POP to fee-based and to kind to get the business and at some in time you said you guys have sustained like the one-time coverage just off fee-based. I know you mentioned, again say in the press release but can we talk about progress that’s been made there and time frame to that actually occurring in your mind? Terry Spencer Yes, I will just make a high level comment. It’s going very well. Producers are engaged with us. We’ve had success. We’ve had some contracts. We are converted more to a fee-based structure than POP. So we are expanding the fee-based component and shrinking the commodity sensitive component that’s gone — it’s gone well. Producers, they want additional services, other things added to their contracts with us, other features and we are working with them on those. So it’s going well. When you think about the regions in which we operate and particularly in the Williston Basin, it’s not like hundreds of contracts we’re having to address, its key producers and just it’s not a whole bunch of contracts, okay? So we expect to have some success as we continue to move forward, have success fairly quickly. Kristina Kazarian And so when we think about that, is it like a ’16, ’17, ’18, how just roughly frame enough maybe? Terry Spencer Yes, it’s going to be more of 2016 benefit to us. Kristina Kazarian Perfect. Thanks guys. That was it from me today. Terry Spencer You bet. Thank you. Operator And we will go to Craig Shere with Tuohy Brothers. Craig Shere Good morning and congratulations. Terry Spencer Thanks Craig. Craig Shere So when you — in the last questioning when you were saying Terry 2016 benefit and some of the conversion to more fee-based from POP processing and contracting, is that to suggest that the vast majority if not all of the distribution could be covered by fee-base by then or is that more a longer term? Terry Spencer Now that’s Craig — that would be a longer term proposition for us, okay. I think it’s a practical goal, I think it makes more sense than perhaps trying to target a percentage of fee and percentage of commodity exposure but definitely it’s a longer term goal. Craig Shere Okay. And Derek expressed the balance between topping ATM and keeping in mind the practical yields these units are trading at in the public market. Even with today’s gains I think we are at stair step of lower price point than what you got on the ATM issuances in the second quarter. Is there a point at which you are just not interested in public issuances and at which without considering major structural changes that the OKE free cash flow and balance sheet strength could be used to bridge funding needs for few quarters? Derek Reiners Yes, Craig this is Derek. I think that’s a good point. Certainly OKE has some additional cash on its balance sheet today and it has certainly got capacity to raise capital there at more attractive yields today. I think it is important to step back and think about the underlying assets of the Partnership and the types of projects that we have, even at these higher yields those projects make sense. And so it’s something we certainly think about very often but and we could consider other types of securities other than just a common unit, we could consider — OKE might consider participation in some form or fashion as well to help that need as well. Craig Shere And Terry as we think about bottlenecks in infrastructure in terms of actually filling out the Bakken Express Pipeline, I know that right now at the $45 oil that’s not what people are thinking about. But thinking overtime, filling up that pipeline at $0.30 plus pricing that’s bundled pricing including all downstream infrastructure. Is the bottleneck there fractionation that would need to be added and how we should think about how much more fractionation is needed to fill up that pipe in terms of the full issue of ethane rejection? Terry Spencer Well Craig it’s a combination of both pipe and fractionation capacity. We are certainly not anywhere near to that point yet but if you think about it very broadly and longer term, if need to get to that kind of next stair step level of production assuming the prices stabilize and rebound, when we think about expanding that whole infrastructure it’s got to be pipes, it’s a combination of lubs, it’s pumps and it’s fractionation capacity you got potentially in the Mid-Continent and Gulf Coast. So you have to think about it broadly, I wouldn’t characterize it as just one particular component. Craig Shere And is there a bookmark you can give in terms of — or book-ins you can give in terms of how billions of dollars of infrastructure we are talking about? Terry Spencer I’ll let Sheridan. Sheridan Swords Well, what I would say, Craig, the other thing to realize is that fracs are not exclusive to one basin. Our system is we can move Y grade around. So would we have to add more fracs if we add more volume out of the Bakken? Possibly if we bring more volume as we’re seeing more volume come out at the Scoop, the Stack and some of those areas, as that comes on that fills up our existing frac capacity as well, so it’s go in there. But right now we think we have enough frac capacity for the volume on the Bakken today as it grows even in a C3 plus rejected volume. We do see a great opportunity out at the Central Oklahoma with the Stack and what’s going on down there in the Scoop that we think — we do think in the future we will be building more fracs. Craig Shere On a separate note, I was a bit surprise the optimization margins weren’t more robust in the quarter, because propane spreads actually got pretty decent even though ethane was pretty anemic still. Can you update us on your ability to capture specific propane differentials even amidst the anemic ethane margins? Sheridan Swords Well, I think the biggest thing you have to look at is when you look at the propane differential through the second quarter — you have to realize if you are going to the LONESTAR facility, which had the highest spread there’s restrictions in getting to that facility. So a lot of what we were able to capture was between Conway and the non-TET or enterprise mark. So that was down cents per gallon from that. We continue to, on the propane side, we continue to convert a lot of our optimization capacity to fee-based. So when we do that that reduces our ability to get a wider spread on margins on what we do ship down there, because we have to ship more and more volume for our third-party people that have, we’ve given them Belvieu access. Craig Shere And just one more, the Bakken gathered NGL volumes are only forecast to rise 5% from July to the fourth quarter. But gathered volumes are guided to rise 14% from 2Q to 4Q. Can you elaborate on that? Sheridan Swords The reason that gathered volumes are continuing to go up, it is definitely a growth out of our Bakken, but we also see growth coming out of the Mid-Continent as we continue to go forward on that. So I think that may be where you are seeing some of that growth happen. Craig Shere I guess — I am sorry, the first number was the NGL volumes and second was the guest gathered volumes all out of Bakken. Sheridan Swords Okay. Kevin Burdick Craig, this is Kevin. On the gathered volumes when you look at the information we provided in the quarter, that is not necessarily a quarterly average that’s saying we will reach that capacity at some point. So, if you just do that math, that’s not saying that there is a, what your number was that’s the average growth, quarter-over-quarter, that just taking look at kind of a peak volume in the third quarter and a peak volume in the fourth quarter. Craig Shere So the numbers are a bit apples and oranges. That helps. Thank you very much. Operator We’ll go to Jeremy Tonet with J.P. Morgan. Unidentified Analyst This is actually Chris on for Jeremy. I guess as noted earlier, I appreciate the color, extra color on the slide deck. When you look at the volume outlook for the second half of 2015 you noted that captured flare gas was one of the key drivers and you also have an inventory of about 145 million cubic feet a day in ONEOK’s dedicated area. And so, we were wondering whether there would be — whether that would be more weighted towards the second half of 2015 or how much of that goes into 2016? Terry Spencer Well, yes, there is a considerable amount in the second half, but it certainly gives you considerable momentum going into 2016. So, it is going to carry you well into 2016 along with the newly completed wells and the backlog of uncompleted wells. So it is all kind of working together. Kevin, you got anything to add to that? Kevin Burdick No, I would just — the one statistic that I think is very interesting to kind of describe some of the improved performance is, if you look at the numbers provided by the state from January to May, oil production when up I think it was around 10,000 barrels a day. But gas production, which was basically flat or maybe a 1% increase, gas production actually went up about 150 million cubic feet a day during that same timeframe. So that demonstrates that as oil states flat with the improved gas to oil ratios, the improved performance gas oil ratios, the improved performance, the gas volumes have continued to go up. Unidentified Analyst Thanks, that’s helpful. I guess moving to West Texas LPG, your JV partner there noted some pretty big expectations in terms of increased pipeline distributions. And so we’re wondering, relative to your plans with that at the time of the acquisition, how are things trending? And with the recent tariff developments and your expectations for I guess returns going forward? Terry Spencer Well, it is going very well. With the tariff increases as well as the volume prospects that we continue to develop, we’ve got high expectations for the pipeline, it’s a great fit with our existing infrastructure, it is of course putting in this premiere basin that we wanted to be in for some time and sets ourselves for continued growth. The performance from a financial perspective is going to improve significantly with these tariff increases and as the volumes continue to be added it’s going to be — it is and it is going to continue to be a major contributor to the segment’s profit. Unidentified Analyst So relative to your planned into time of the acquisition, would you say that’s higher or? Terry Spencer I think the — what our expectations when we had the acquisition we’re progressing right along those expectations. Unidentified Analyst Thanks, it’s helpful. And then I guess lastly from me. On the re-contracting front in terms of your percentage of proceed contracts. For 2016, would you expect any kind of lower returns from those contract negotiations or what kind of give and take do you have with producer customers in that regard. Anything there would be helpful? Terry Spencer Well the strategy is to enhance our returns and obviously these contracts have been affected by the lower commodity price environment and certainly at these price levels and the resulting margins it makes it difficult to realize an acceptable return. So we are not going to sacrifice return and as we continue to work with these producers and provide enhanced services and we have demonstrated that we have been able to put contracts together that make sense and get our returns to an acceptable level. Unidentified Analyst Thanks. Appreciate the color. Terry Spencer You bet. Operator And we will go to John Edwards with Credit Suisse. John Edwards Yes, good morning everybody and congrats on a nice quarter. Just coming back to the financing questions, you have indicated you are open to alternative approaches here. So I take it that you would also include things like subordinating yields, take units, perhaps even cash injections from OKE using OKE equity. Would that be fair? Terry Spencer Yes, that would be fair. We continue to evaluate all of those levers. John Edwards And then I am just curious on the projects that have been suspended Terry, kind of what’s the thoughts behind those perhaps any color on when you think you would be able to bring those back into say execution mode? Terry Spencer No specific dates at this particular point in time but again we continue to assess the current market environment which is very volatile and uncertain. It is — and we continue to assess the environment and when the environment makes sense and when the producers need that capacity certainly we will fire those projects back up, okay. Right now we are continuing to — we are still in a wait and see mode on those suspended projects. John Edwards Okay and then just any thoughts regarding your plans with all the recent increases in M&A activity? Terry Spencer Well, our plans are going to be the same. We are going to stay organically focused to the extent of we participate in M&A from a strategic asset standpoint that is we — when people ask me about M&A I am like okay yes we are interested in M&A particularly as it relates to strategic asset acquisitions like our West Texas pipeline in the Permian. So yes we are going to stay active and focused and look at opportunities. But at the end of that day what happens out there in the M&A arena, we don’t have a whole lot of control over that. We will just keep our heads down and stay focused and continue to drive risk out this business and serve our customers. John Edwards Okay. Great. That’s it from me. Thanks. Terry Spencer Yes. Operator Next is Michael Blum with Wells Fargo. Michael Blum Hi, thanks, so two quick ones. Just one more question on the West Texas LPG pipeline. When you acquired the asset you laid out a plan to spend a significant amount of capital over the next few years and expand the capacity of the line, obviously you have executed on increasing rate already. Has anything changed there or is that still all kind of on plan? Sheridan Swords Hi Michael this is Sheridan. Yes, we have been talking to quite a few producers out there that will backstop expansion. So we are progressing as planned on that and we are very hopeful hear pretty soon that we will be able to come out and announce expansion of the pipeline. So the Permian has still been resilient. We are still seeing growth and we are getting most people call on us about trying to get on this platform, as we still think with the assets that we have we can be extremely competitive versus the marketplace out there. Michael Blum And then just I apologize if I missed this but could you quantify the reduction in ethane rejection you saw this quarter? Sheridan Swords In the Bakken is about 20,000 barrels a day in June. So that’s 20,000 barrels a day in June, so you can put over about 7,000 barrels a day on average for the quarter. Operator We’ll go to Becca Followill with U.S. Capital Advisors. Becca Followill If this already been asked, if it has just tell me to go listen to — look at the transcripts, but on the ethane rejection, why is it occurring now? What has changed in having to add more ethane in to help the spec? Terry Spencer Well, Becca, I think the short answer, and I will let Sheridan follow-up, but I think the short answer is just the volume growth, significant volume growth that we kind of broke over to a point where the NGL production has gotten so big to the point where now this issue emerging is something significant. Sheridan Swords Yes, I would say you are exactly right. It is fundamentally that we’ve had end use people call us and say that the propane is off spec and we need to clean it up. Becca Followill So, it is just you reached a tipping point? Sheridan Swords Yes, that’s right. Becca Followill And then going forward, as you continue to produce volumes and you will have to produce more ethane in order to keep it in balance, is that correct? Sheridan Swords It will be. We are working on a long-term plan that we can clean this up at our fractionators so that we do not have to continue to extract this ethane. But that is going to take some time to construct and get in place. But we are working, our engineers are working on a long-term solution. Terry Spencer And the only thing I will add is that is not done for free. Becca Followill So your shippers will have to pay for that? Terry Spencer Likely so. Operator And next line is Eric Genco with Citi. Eric Genco I just wanted to go back to the — and I guess not to beat a dead horse. The percent of proceeds to fee based. Your fee-based rate ticked up to $0.39 from sort of the mid-30s this quarter. Is that related to your efforts to move towards more fee-based? Terry Spencer I think the short answer is yes. Eric Genco And I guess as I was looking at it last night, is the strategy then to move towards more of a fee-based cut or a hybrid contract structure where maybe if commodity prices are low you get an extra fee payment? Because your equity volumes for NGLs and for residue gas actually ticked up a bit relative to the overall production levels. And I would have thought if that was moving towards fee-based that that would have been down or flat. So, I was just curious to whether this is more of a hybrid move or whether this is a pure conversion. Kevin Burdick Eric, this is Kevin. It will be — it is a combination. I mean there we talk about converting to more of a fee-based margin. There are a variety of ways that we get there. One is, like you said, is just increasing the fees and increasing the POP percentages, that kind of trade-off. There is other ways that accomplish the same thing. So our goal, like Terry has talked previously, is each of our customers is different. They are looking for different services. Those different services may require different strategies in how we go about working with them to get to the right mix of what is that. But in all the scenarios, it does result in a higher fee, but it may not, a fee-based margin, but it may not necessarily correlate to a lower equity volume. Terry Spencer And, Kevin, the only thing I would add to that is that when you think about our business as a whole, we’re keenly focused on bringing new fee-based opportunities and fee-based projects to the table. And in Phil’s business segment, as we mentioned in the remarks, the Roadrunner pipeline and its OWT expansion are important. And on OWT expansion, in particular, is a good example of the additional projects that have spun off as a result of this Roadrunner project in establishing a conduit to those markets in Mexico. So we’ll be very focused and remain very focused on fee-based opportunities and that will help bring that fee-based percentage up as we go forward. Eric Genco So is it fair to say then that that $0.39, at least, probably while commodity prices remain low, is probably fairly sticky at this point? And then perhaps as commodity prices recover maybe that falls back a little bit to where it should have been, but it doesn’t matter because you have retained the upside in these contracts? Terry Spencer No, I don’t think so, Eric. I think that as we continue to renegotiate that fee should go up. So, yes, I don’t think that that rate is going to be driven much by or affected much by a move in commodity prices. Eric Genco And I had a couple other quick ones just to sort of — some of the numbers you gave on the last quarter’s conference call, and I think you repeated them, but I just want to double check. So there is about 900 drilled uncompleted wells in the Bakken right now and I think last quarter you said about 50% is on your acreage, so that is basically the same –? Terry Spencer That is correct, roughly 50%. Eric Genco And I think you said last quarter that there were 50 rigs drilling on your acreage. I was curious; did you give a number for that today? Terry Spencer Yes, we did. Eric Genco Okay, what was that? I’m sorry. I missed that. Terry Spencer We’re in the 40 range right now. Eric Genco 40 range…. Terry Spencer Yes, and again that moves up and down. But all of that has been in line with our expectations. Eric Genco Okay. Terry Spencer The only thing I would add to that is keep in mind that these IP rates is the average initial production rates on these wells just continue skyrocket. And I was just reading some materials the other day from some of our customers or some of our producers rather, and it’s really remarkable the improvement that we are seeing. So even if you see rig reductions we are seeing these increased IP rates that are more than offsetting some of those reductions. Eric Genco I think that’s fair, I think in some of the instances we’ve been looking at — some assumptions it takes about 24 days to drill well and some of these things but we are hearing some things maybe it’s fallen down to almost the 16 range for some people so. I guess we would count as not the end all be all that it used to be. Terry Spencer Yes. Eric Genco I also just wanted to ask real quick. Of the 900 drilling completed wells in the basin what you view is sort of being an equilibrium number for that? I mean there’s always going to be some number of uncompleted wells and I was just curious overall for the basin what do you think is normal? Terry Spencer That’s a tough one to answer. I mean because especially as producers have shifted almost entirely now to kind of the multi-well pads and those stick a rig and at a spot and then drill several wells and that — so you kind of have an artificial working inventory if you will of completed — of uncompleted wells. I think there is some as we have talked with others in North Dakota is that 300, 400 ranges that will kind of always be there as a working inventory as long as you are at this kind of a rig count, you may be in that range. But again that can fluctuate as again as rigs move around and what, where and how they are drilling. Eric Genco Okay. Well, thank you very much. That’s all I had. Terry Spencer Thank you. Operator We will go to Andy Gupta with HITE Hedge. And it appears he does not have a question. So we will go to Matt Niblack with HITE. Please go ahead. Matt Niblack Hi. I just wanted to make sure I understood what you said at the beginning of the call properly that you had ample of liquidity particularly given how credit metrics are calculated by your borrowers that there is no need to issue okay equity at these FX valuations? Terry Spencer Well I don’t know that I have said that. We have been pretty clear that we expect to continue to issue equity as we balance our credit metrics with issuing at this price. Matt Niblack Okay. But you said you’re going at least avoid the disruptive overnight offering given the ATM program? Terry Spencer Well I mean we talk about the overnight markets all the time and we certainly continue to look at that option. As we said many times the ATM program has worked pretty well for us. We were able to get quite a bit done in the second quarter, so to avoid that overnight market issue but I can’t wool that out for you. Matt Niblack Okay. Thank you. Operator And that will conclude our question-and-answer session. I would like to turn it back for any additional or closing remarks. Terry Spencer Thank you. Our quite period for the third quarter starts when we close our books early October and extensive earnings are released after the market closes on November 3rd, followed by our conference call on November 4. Thank you for joining us and have a good day. Operator Thank you very much and that does conclude our conference for today. I would like to thank everyone for your participation and have a great day.

Targa Resources’ (TRGP) CEO Joe Bob Perkins on Q2 2015 Results – Earnings Call Transcript

Targa Resources Corp. (NYSE: TRGP ) Q2 2015 Earnings Conference Call August 4, 2015 10:30 AM ET Executives Jennifer Kneale – Senior Director of Finance Joe Bob Perkins – CEO Matt Meloy – CFO Analysts Matthew Phillips – Clarkson Sunil Sibal – Global Hunter Securities Brandon Blossman – Tudor, Pickering, Holt & Company Darren Horowitz – Raymond James TJ Schultz – RBC Capital Jeremy Tonet – JPMorgan Schneur Gershuni – UBS Michael Blum – Wells Fargo John Edwards – Credit Suisse Faisel Khan – Citigroup Corey Goldman – Jefferies Gregg Brody – Bank of America Merrill Lynch Jeff Mccarter – Citadel Ethan Bellamy – Baird Charles Marshall – Capital One Securities Operator Good day, ladies and gentlemen and welcome to the Targa Resources’ Second Quarter 2015 Earnings Webcast and Presentation. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator instructions] I would now like to turn the conference over to Jennifer Kneale, Senior Director of Finance. You may begin. Jennifer Kneale Thank you, Nicole. I’d like to welcome everyone to our second quarter 2015 investor call for both Targa Resources Corp. and Targa Resources Partners LP. Before we get started, I would like to mention that Targa Resources Corp., TRC, or the Company and Targa Resources Partners LP, Targa Resources Partners or the Partnership, have published their joint earnings release, which is available on our website at www.targaresources.com. We will also be posting an updated investor presentation to the website later today. I would like to remind you that any statements made during this call that might include the Company’s or the Partnership’s expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities Acts of 1933 and 1934. Please note that 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, including the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 and quarterly reports on Form 10-Q. Speaking on the call today will be Joe Bob Perkins, Chief Executive Officer; and Matt Meloy, Chief Financial Officer. Joe Bob will start off with a high level review of performance and highlights. He will then turn it over to Matt to review the Partnership’s consolidated financial results, segments results and other financial matters. Matt will also review key financial matters related to Targa Resources Corp. Following Matt’s comments Joe Bob will provide some concluding remarks and then we will take your questions. There are also several other members of the management team available who may assist in the Q&A session. With that, I will turn the call over to Joe Bob Perkins. Joe Bob Perkins Thanks, Jen. Welcome everybody and thank you for joining us this morning. I’d like to remind you that this is the first reported quarter that includes the full quarter of results from our Targa Pipeline or TPL assets, which were a partner on merger that closed on February 27. As we describe our results from the quarter, the inclusion of TPL in Field Gathering & Processing segment, naturally will be the biggest factor in a number of increases as we compare results to last year and to last quarter. Turning to Targa’s second quarter results. Our reported second quarter adjusted EBITDA was $303 million as compared to $229 million for the second quarter of last year. This 33% increase was driven primarily by the inclusion of TPL’s assets for the full quarter, which more than offset lower commodity prices. Our distributable cash flow for the quarter of $219 million resulted in distribution coverage of approximately 1.1 times based on our second quarter declared distribution of $0.825 or $3.30 per common unit on an annualized basis. The Partnership’s second quarter distribution represents a 6% increase compared to the second quarter of 2014. At the TRC level, the second quarter dividend of $0.875 or $3.50 per common share annualized represents a 27% increase compared to the second quarter of 2014. Through the price swings we have seen to-date in 2015, our Field Gathering and Processing volumes continued to grow through the first six months of the year compared to the fourth quarter of last year. Natural gas inlet volumes increased in the second quarter compared to fourth quarter across eight of our nine systems. Overall, Field Gathering and Processing volumes were up more than 5% second quarter of 2015 over fourth quarter of 2014. For the second quarter versus fourth quarter, we experienced a slight volume decrease in North Texas from reduced activity levels and from the impacts of severe flooding in the area. In the absence of the commodity price rally, we expect that North Texas volumes are likely to decline for the balance of the year. All of our other field operations had volume increases versus the fourth quarter of 2014. And as we look at expected volumes for the balance of the year in the Permian Basin, the Badlands and SouthOK, we expect some continued growth in each of these areas. As you are all well aware, commodity prices continue to be volatile. In May and June, spot crude prices rallied to over $60 per barrel and recently fell below $50 per barrel. Yesterday WTI was about $46 per barrel. While there continues to be uncertainty on price and related activity levels, our current expectations for average 2015 field GMP volumes is 3% to 5% overall growth in 2015 versus Q4 2014. This is slightly higher than our previous guidance of flat to low-single digit growth on the same comparison. For the most part, we are seeing continued activity around our field GMP areas of operations, but obviously less than we were experiencing in 2014. We are also seeing Targa’s strong operational capabilities, reputation for customer service and willingness to spend capital selectively for attractive projects that have allowed us to capture some existing and future producer volumes from other Midstream companies. Predicting 2016 field GMP volumes continues to be more ordinate science. Producers have demonstrated their willingness to increase their pace of drilling in almost all of our areas if crude prices improve to for example $60 per barrel. However, our ability to predict 2016 prices and therefore produce our expectations for those prices has not improved. In April, we said that if commodity prices didn’t improve April levels, average 2016 field GMP volumes maybe lower than 2015. Predicting 2016 field GMP volumes continues to be difficult, but I want to say that we generally feel a bit more optimistic about volumes than we did at the first of the year. Now, as we said, we project that 3% to 5% volume growth from Q4 2014 to average 2015, which slightly puts Targa at a better 2016 beginning spot than we were expecting. Looking at DOE US onshore oil production data, we see a decline in April and May, which probably is a good thing for the industry. That’s obviously the net result of some areas growing and some areas declining. We are seeing growth in our most important areas and expect that to continue at least through the near term, proving that we have strong positioning. So we feel a bit more optimistic for 2015 and to some extent 2016, not because of an improved price outlook, but because of volume results to-date. Moving to downstream, our Logistics and Marketing division operating margin for the second quarter of 2015 was slightly higher than the same time period last year. As for full year 2015, I guess we reaffirm our guidance of Logistics and Marketing division operating margin may be modestly lower than 2014. In the second quarter, we exploited approximately 5 million barrels per month of LPGs, which was 3% higher than the second quarter of 2014. Demand for LPG exports has been impacted by global commodity prices in the tight shipping market, but we are seeing continued demand for short and long-term contracts and we have continued to add contracts for the second half of 2015 and beyond. We expect our LPG export activity levels to be at or above Q2 volumes for the remainder of the year. Given our contract portfolio, current market dynamics related to commodity prices shipping constraints and increased competition, we expect overall second half LPG export operating margins may approximate what we have seen so far this year. Across our other businesses, we have worked hard through the first two quarters of the year to reduce operating expenses, especially in the field GMP businesses without sacrificing safety or preventative maintenance and while still meeting customer needs for growing volumes. With the inclusion of TPL and the addition of assets throughout 2014 and early 2015, and because fuel and power consumption are included in expenses, it’s difficult to see the savings in our reported numbers. When we look at our internal numbers for full year 2015, we currently expect field GMP operating expenses to be approximately 8% lower than our budgeted expectations despite the increase in volumes we have been experiencing being gathered in process. Our performance in the second quarter highlights the diversity and resiliency of our business mix. There were some pluses and minuses, but overall it was a strong performance quarter in the context of weak commodity prices. Given the first two quarters of distribution announcements at TRP, our 2015 distribution growth over 2014 is likely to be towards the lower end of our 4% to 7% distribution growth guidance. At TRC, we continue to expect 25% or better dividend growth in 2015 over 2014. That wraps up my initial comments and now I will hand it over to Matt. Matt? Matt Meloy Thanks, Joe Bob. I’d like to add my welcome and thank you for joining our call today. As Joe Bob mentioned, adjusted EBITDA for the quarter was $303 million compared to $229 million for the same period last year. The increase was driven by the addition of the TPL assets, which are reported in our field GMP segment. Overall operating margin increased 17% for the second quarter compared to the same time period last year and I’ll review the drivers of this performance in the segment reviews. Net maintenance capital expenditures were $28 million in the second quarter of 2015 compared to $20 million in the second quarter of 2014 driven by the inclusion of TPL operations offset by some of the cost savings Joe Bob discussed across all of our operating areas. Turning to the segment level, I’ll summarize the second quarter performance on a year-over-year basis, and we will start with our downstream business. In our Logistics and Marketing division, our second quarter operating margin increased 1% compared to the first quarter 2015 driven by partial recognition of the payment received from Noble related to our condensate splitter project, increased terminaling and storage activities and higher fractionation volumes. Fractionation volumes increased by 3% versus the same time period last year and overall operating margin from fractionation was down slightly as a result of lower system product gains and higher maintenance cost. We loaded an average of 5 million barrels per month of LPG for exports and second quarter 2015 operating margin from LPG exports was approximately flat compared to the same time period last year. In our Gathering and Processing division, our Field Gathering and Processing segment operating margin increased by 41% compared to last year largely driven by the inclusion of TPL. Second quarter 2015 natural gas plant inlet volumes for the Field Gathering and Processing segment were 2.67 billion cubic feet per day, 195% increase compared to the same period in 2014. The overall increase in natural gas inlet volumes was due to the inclusion of TPL volumes in West Texas, South Texas, SouthOK and WestOK and increases in each of the following business units, 34% at SAOU, 23% at Badlands, 9% at Versado and 7% at Sand Hills. Inlet volumes at North Texas approximated second quarter 2014 levels and as Joe Bob mentioned, we are impacted by severe flooding conditions and subsequent impacts that affected the area throughout the spring. Crude oil gathered increased to 106,000 barrels per day in the second quarter, a 27% increase versus the same time period last year. For the Field Gathering and Processing segment, commodity prices were down across the board, with NGL prices decreasing by 52%, condensate prices decreasing by 47% and natural gas prices decreasing by 45% compared to the second quarter of 2014. Our hedging activities, which mitigate a portion of these price swings are included in our other operating segment. In our Coastal Gathering and Processing segment, operating margin was down 70% in the second quarter of 2015 versus the same time period last year as Gulf of Mexico and Onshore Gulf Coast volumes continue to decrease. Let’s now move to capital structure, liquidity and other matters. As of June 30, we had 878 million of outstanding borrowings under the Partnership’s 1.6 billion senior secured revolving credit facility due 2017. With outstanding letters of credit of 21 million, revolver availability was about 702 million at quarter end. Total liquidity, including approximately 86 million of cash on hand, was about 787 million. At quarter end, we had borrowings of 124 million under our 300 million accounts receivable securitization facility. Year-to-date, we have received net proceeds of approximately 375 million from equity issuances, including general partner contributions. For April through July, we received approximately 263 million of net proceeds from asset market equity issuances and obliged $316 million in net proceeds under the ATM equity program year-to-date. On a debt compliance basis, which provides us adjusted EBITDA credit per material growth projects that are in process but not yet in complete and makes other adjustments, TRP’s total compliance leverage ratio at the end of the second quarter was 3.8 times. Next, I’d like to make a few comments about our fee-based margin, hedging and capital spending programs for 2015. For the second quarter of 2015, our operating margin was 72% fee-based. For 2015, we now expect at least 70% of our operating margin to be fee-based. Since the end of the first quarter, we continue to layer on hedges using costless collars and swaps and for our current estimate of equity volumes from Field Gathering & Processing, we estimate we have now hedged approximately 70% of the remaining 2015 natural gas, approximately 60% of the remaining 2015 condensate and approximately 30% of remaining NGL volumes. For 2016, based on our estimate of our current equity volumes, we estimate that we have hedged approximately 45% of natural gas, approximately 35% of condensate and approximately 15% of NGL volumes. Moving on to capital spending. We continue to estimate approximately $700 million and $900 million of growth in capital expenditures in 2015, which includes ten months of CapEx related to the TPL systems. Next, I’ll make a few brief remarks about the results of Targa Resources Corp. Targa Resources Corp stand-alone distributable cash flow for the second quarter 2015 was $52 million and TRC declared approximately $49 million in dividends for the quarter, resulting in dividend coverage of approximately 1.1 times. On July 21, TRC declared a second quarter cash dividend of $0.875 per common share or $3.50 per common share on an annualized basis, representing approximately 27% increase over the annualized rate paid with respect to the second quarter of 2014. As of June 30, TRC had $460 million of outstanding borrowings and $210 million of availability under TRC’s $670 million senior secured credit facility and $160 million of outstanding borrowings under TRC’s senior secured term loan resulting in about 2.6 times debt compliance ratio. At TRC, we continue to expect 5% to 10% effective cash tax rate for 2015 and in the near term beyond 2015 and effective cash tax rate of less than 15%. That concludes my review and I’ll now turn the call back over to Joe Bob. Joe Bob Perkins Thank you, Matt. Five months have passed since we acquired TPL. We really like the assets, our people are working as one team and the target team is continuing to mine opportunities across our combined footprint. We are working on connecting West Tex and SAOU later this year, enhancing options for producer customers and allowing us to spend capital even more efficiently with West Tex, SAOU and Sandhills connected together in the Permian Basin. These interconnections, you will recall that we connected SAOU to Sandhills last year for buy more flexibility to meet customer needs and to access existing capacity for growth. Along with the connection of West Tex and SAOU, we may also restart the idled 45 million cubic feet per day Benedum Plant in Upton County. These projects do not require much capital. Given that we are operating at near capacity in the Permian Basin, the flexibility associated with connecting existing systems and existing plants and having an idled plant to restart is very valuable. We also expect to complete the Buffalo Plant in Martin County in 2016 with timing dependent on volume growth. We can have that plant completed and running in six months, six months after we make the decision with our joint venture partner, Pioneer Natural Resources to go ahead with the final stages of construction. Similarly, activity around our Versado system in the western part of the Permian Basin continues. We are adding another compressor station and lined a new 16-inch line to better access available capacity at our Monument Plant, serving additional volumes from the Delaware Basin to the Southwest. This is an example of capital spending that isn’t significant enough to be a single line item on our published CapEx projects, but it is a capital well spent given the returns associated with bringing new volumes to an existing plant that has available capacity. In the Badlands, we are making solid progress in securing right-of-way to lay pipe on reservation lands, which will allow us to secure volumes from wells that have already been drilled. Due to time required to move from right-of-way acquisition to approval to construction, this progress will likely not impact volumes until late this year or in 2016. Our little Missouri 3 plant came online in the first quarter and we’re continuing to see natural gas volumes increase to more than 50 million cubic feet per day in July. At the same time, crude oil volumes also ticked higher in July to more than 110,000 barrels per day. Given crude prices to-date, we have seen a significant decrease in rig activity in the broader Bakken and in the number of well permits filed in North Dakota. If you look at our systems across Mckenzie, Dunn and Montreal Counties, we’re positioned in one of the most active areas of the basin, as evidenced by the number of rigs running around our system relative to the rest of the basin. The right-of-way progress on the reservation is particularly important because it will allow us to lay previously delayed pipe and capture volumes that will support our system in 2016 and beyond. We’re now seven months through a roller coaster year related to prices for crude and NGLs, where in the second quarter alone, Mont Belvieu propane prices, for example, moved from a high of $0.58 per gallon in April to a low of $0.31 per gallon in June and we’re at about $0.36 per gallon as of yesterday. During such times of price volatility, interconnected flexible facilities including LPG storage can become increasingly valuable. We’re optimizing the use of our facilities for customer and target business mix. As domestic production has increased this year, we’ve seen continued demand for fractionation services. Construction on train pipe continues and it should be in service mid-2016. We’re also through the first public notice period related to our Train 6 permit with a similar size and scope as Trains 4 and Trains 5. We continue to work closely with Noble as they neared decision point on determining whether to move forward with a new terminal at Patriot, a condensate splitter at Channelview or some combination of both projects. Subject of final project scope and permitting, we would expect that the splitter or terminal or both projects would be operational in 2017. In closing, we have been operating in an uncertain environment and I’m incredibly proud of our execution across the Targa footprint in the second quarter. We cannot control commodity prices but our day-to-day focus is on safety, meeting customer needs, cost savings and efficiency of capital spending, without sacrificing customer service or ignoring low cost options, which may benefit Targa in the event of increased activity in the future. Continued execution across our well positioned diversified asset base has resulted in a strong first half for Targa. There is upside potential in the balance of the year, most obviously from the following. First, tailwinds associated with potential improvements in commodity prices from our current levels. Secondly, in the field, achieving volumes that are greater than expected from existing production, continued success competing for takeaway gas and efforts to continue to drive costs lower. And third, improving LPG export volumes and/or LPG export unit margins from our expected levels, perhaps as the market benefits from additional vessels coming online in the back half of the year. Targa’s strong execution performance in the first half of the year is driving quarter-over-quarter distribution and dividend growth, consistent with our expectations for the year and we will continue to execute in the second half of the year. With that, let’s open up the line for questions, operator. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from the line of Matthew Phillips of Clarkson. Your line is now open. Matthew Phillips [indiscernible]. Joe Bob Perkins Hey, good morning. Matthew Phillips A quick question on the hedge book. You have an add-back on DCF of $24.8 million. I was wondering how that squares with the $17.1 million in gross margin on the commodity derivatives activity? Joe Bob Perkins Yeah, sure, good question. The $17.1 million in the other operating margin is essentially a legacy Targa or existing Targa hedge add-back. The TPL hedges in acquisition accounting were put on the book with fair value and so, as we collect those proceeds, it’s not hitting the income statement. So, we’re adding back the cash received in a quarter as those contracts settle. So, you’ll see that on a quarterly basis as we essentially receive the cash from the TPL hedge book. Matthew Phillips So, the TPL hedges are added back whereas the legacy Targa hedges are on the income statement? Joe Bob Perkins Yeah. They’re already in there. Yes. Matthew Phillips Okay. Great, thanks. And then moving on to LPG exports, you’ll add about 15% decline from 2Q – from 1Q and 2Q. However, looking at the vessel data, it looks like July was a record month for the U.S. Can you confirm if you’ve seen an uptick in July exports and what that might mean for margins? Matt Meloy We have seen some continued – I’d say seen some strong activity here thus far third quarter. As Joe Bob said, there were – we would the back half of the year to approximate Q2. Things might get a little bit better for us but that’s kind of what we’re seeing right now. Matthew Phillips Approximate to Q1 on a margin basis or both? Matt Meloy What we said was approximate Q2 for the back half of the year on a volume basis. I’d say, we’ve seen things a little bit stronger than we had in the previous few months, but we expect volumes to kind of approximate the second quarter. Joe Bob Perkins We also said that performing better than that was a potential upside and we said that our guidance continue to remain for the downstream to perhaps be modestly lower in 2015 than 2014. We like to outperform expectations. Matthew Phillips Yeah. Well, I mean margins from this have fallen off since 4Q, the past two quarters. But I mean, if volumes are coming back, I would think that might give you a little margin strength. Is that reasonable? Joe Bob Perkins I think we’ve kind of trying to relate it all. Matthew Phillips Okay, thank you. Operator Thank you. And then the next question comes from Sunil Sibal of Global Hunter Securities. Your line is now open. Sunil Sibal Hi, good morning guys, and congrats on a good solid quarter. Joe Bob Perkins Thanks, good morning. Sunil Sibal A couple of questions from me. In terms of the LPG export volumes that you saw second quarter, is it fair to assume they were all primarily contracted volumes or you had some spot volumes in there too? Joe Bob Perkins We haven’t given a detailed breakout of what is spot and what is contractive. I would say, we have seen as we’ve continued to over the previous quarters, a significant portion of our volumes loaded or contracted but we were able to load some shorter-term or spot cargos as well in the second quarter. Sunil Sibal And then on the hedge book for 2016, seems like on NGLs, you maintained your hedge positions from the first quarter. I was wondering if you could give us some – in terms of your thought process on that and what levels you feel comfortable hedging that ex-player? Joe Bob Perkins Yeah. We have layered on some hedges. In the first quarter, we layered on some hedges, in the second quarter, we actually layered on some additional hedges here early in the third quarter. We’ve added some costless collars, we’ve added some swaps for the various products, crude, NGLs and natural gas. In this environment, I don’t think we’re looking to kind of catch up to get back to those targeted levels all that once but we do continue to take a disciplined approach to try and continue to layer on some amount of hedges where it makes sense. Sunil Sibal Okay. And then lastly, some of your producer customers have been pretty vocal about economics of drilling even in the wake of this commodity price weakness. I was kind of curious does that jives activity levels you are seeing in your assets? Joe Bob Perkins We obviously read the same public statements and then we have communications that aren’t public. I would say that our broader knowledge is consistent with the public statements of our customer base and we even referenced in our comments that, for example, some producers intent to increase their activity levels at, for example, $60. We are encouraged by the activity levels to-date, but we are not very good at predicting prices. Sunil Sibal Okay, that’s very helpful and that’s all I had. Thanks guys. Joe Bob Perkins Okay, thank you. Operator Thank you. Our next question comes from the line of Brandon Blossman of Tudor, Pickering, Holt & Company. Your line is now open. Brandon Blossman Good morning, guys. Joe Bob Perkins Good morning. Brandon Blossman Follow on to the gathering and processing throughput volume, so the comment was 3% to 5% up ‘15 over I believe Q4 ‘14. Joe Bob Perkins Yes. Brandon Blossman Is that just producer – your current customer base’s volume increase or is there some presumption of market share – incremental market share grab there? Joe Bob Perkins The actuals achieved to-date have been both. We tend to be conservative about our projections going forward. I would like to believe that we continue to benefit from takeaway gas, but we haven’t overestimated that. Brandon Blossman Okay, fair enough. I will try the LPG export at slightly different angle here, is there anything in the back half of ‘15 into ‘16 that would point to your volume throughput being different than kind of the US in total numbers as we see those data – that data role out? Joe Bob Perkins I am not sure we’ve got a real good projection of forward US data. We’ve got a pretty handle on how our volumes are likely to behave and we’ve built that into our comments in the answers to the last question. Brandon Blossman Okay, fair enough. And then more discretely, on a per unit basis, GMP OpEx looks like it’s trending down very nicely over the last two or three quarters. What should we expect as far again on a per unit basis the trajectory through the back half of ‘15 on that metric? Matt Meloy We are going to continue to work on maintaining the cost reductions that we’ve achieved and realizing additional cost reductions. I don’t have a prediction for you in terms of a percent trend, but the efforts are going to continue and our people are very focused on it. Brandon Blossman So, flat to down is a fair takeaway there? Matt Meloy We are pleased with the downward trend that we can see from our internal numbers and that are harder for you all to see from reported numbers despite increases in volumes and that’s pretty extraordinary in the gathering and processing patched. And with expected continued growth for 2015 in those important areas we still expect to do so without increasing our cost. Brandon Blossman Okay, awesome. Thank you very much. Operator Thank you. Our next question comes from the line of Darren Horowitz of Raymond James. Your line is now open. Darren Horowitz Joe Bob, couple of quick questions on field GMP and I appreciate the comments around the plus 3% to 5% overall volume growth even that of what’s going on in North Texas, but what I am more concerned about is the margin expectation to the extent that you can comment, I am just trying to get a feel for the lower operating expense, expected to continue through the back of this year. With the regard to the aggregate impact on gross operating profit for field GMP, how much lower or what’s the variability in terms of your back half of ‘15 margin versus what you’ve already experienced in the first half of ‘15? Joe Bob Perkins As we look second half versus first half, we expect to achieve similar or better. I think that’s about as precise as I can be. Darren Horowitz Okay. Let me jump over to North Texas, specifically the amount from a contractual perspective, POP contracts, I think previously you had said it’s somewhere around 30% of the 2015 margin was going to be POP and a lot of that was really around North Texas. I am just curious, now that you’ve got half of the year behind you and you are looking forward with the TPL assets, what’s that level of expectation for POP exposure in the back half of this year and then into ‘16? And from a re-contracting perspective as maybe you think about shifting some of that exposure to a more fee-based composition of cash flow, how do you think about the margin degradation maybe being offset by volume improvement or cash flow security? Matt Meloy Hey, Darren, it’s Matt. I want to talk just about North Texas just to clear one thing up there first. The North Texas is a POP business up there, so we do have some fees kind of embedded in those contracts whether it’s gathering or compression or others, but we think of North Texas as POP and we don’t really see that changing as we come back of this year and into 2016. Darren Horowitz Okay. And then last question from me and Joe Bob, again I appreciate it being difficult to predict crude oil prices, we struggle from the affliction. But I am wondering just with regard to the balanced assets McKinsey down in Montrose counties right, like a lot of that hinges not just on the absolute price but on the discount to TI, because I think that’s probably where the greater challenge is. So what are producers telling you just from a net back perspective in terms of where the cash price gets more economic? Joe Bob Perkins As opposed to me describing what producers are telling me and not telling the public, what I can see is activity at the price levels that we’ve seen since the first of the year and that activity as you know isn’t driven by the spot price in the particular month, but their outlook for those prices. It’s one of the best oil basins in the world. The differentials as a percentage have moved around since the first of the year. Darren Horowitz Thank you. Joe Bob Perkins That’s about as best we can describe. And like we said, we have several reasons in the Bakken to be optimistic about volumes even at low North Dakota activity levels. The activity levels around our system are better and given the activity levels around our system, we still have some backlog of volumes that we are going to be getting to, thanks to progress on right of way on the reservation. That’s going to take us a little while and thanks to the progress at the Little Missouri 3. The Little Missouri 3 plant provided for helping to put out players and meet customer needs of gas production that was already there and not being captured. Operator Thank you. And our next question comes from the line of TJ Schultz with RBC Capital. Your line is now open. TJ Schultz Hey, good morning. Joe Bob Perkins Good morning. TJ Schultz On field GMP volumes, I guess just questions on 2016, I think the optimistic outlook that you guys kind of commented in the remarks, is that just a fact that you are likely to have a better beginning level or is there something specific maybe you guys gleaned here more recently with the swing and grew to 60 and now back down that gives you more optimism maybe about producer activity kind of within this oil range that we have been bouncing around? Joe Bob Perkins Our feeling a bit better about it has to be in the context of lot of those things you just mentioned, but it wasn’t kind of the short term movement in prices. Number one and the primary reason is volumes have performed better than we expected despite prices over the first half of the year. If you took our last quarter call, for example, spot prices and forward prices are lower than our last quarter call, but given those prices, the volumes have exceeded our expectation. So the volume to price relationship is important in our feeling a bit better. And then, yes, the US data around supply and demand and a break over on crude volumes which occurred a little later than we thought it would, I think works into the mix as you referenced. But that primary thing and we try to say it as we feel a bit better because volumes have done a bit better in spite of pricing. TJ Schultz Okay, thanks. On exports, I think you said you are adding contracts, just any color on the appetite for short term versus long term contracts and then also just any update on constraints that ship availability is having for you guys through the rest of the year? Joe Bob Perkins We’ve guided both since our last call. We are more contracted than not contracted in the near term. We know that ship constraints are a factor. Our ability to predict exactly how fast those additional ships come on or where they come on is not as good as other analysts out there, but we know our customers have felt the ship constraints. We sort of gave you an expectation and then also pointed to it as a potential upside relative to our overall expectations. TJ Schultz Okay, thanks. Operator Thank you. Our next question comes from the line of Jeremy Tonet of JPMorgan. Your line is now open. Jeremy Tonet Good morning. Joe Bob Perkins Good morning. Jeremy Tonet Congratulations on the good quarter there. Just I had a question on the TPL hedge book. It came in a bit stronger than what we were anticipating. So just want to see if you have static commodity price environment, whether the pace of cash gains is going to be stable through ‘15 or if it is more front half of the year weighted. Matt Meloy So we will be filing the Q here shortly and it will have an update of all the hedges that we have on, so it really depends on your commodity price expectation for the amount of cash that we will receive in any quarter. Jeremy Tonet Exactly, I was just curious if there was – the contracts were more weighted to the first half versus back half for the TPL hedges you picked up? Matt Meloy Yeah, we will have less amount hedged and at lower prices kind of generally as we go through time. So I think that’s a fair assessment. Jeremy Tonet Got you. I appreciate that. And Joe Bob, want to touch on some of the things you are seeing before I know it’s a very difficult question, but I am just wondering system-wide, if you are looking at the futures curve, is there a number in your mind where you feel good about continued growth? Is 16, is that 50 versus 60, is there any goal posts you could give us there as far as how you think the target assets would react in when you’d see growth? Joe Bob Perkins Well, I wish I was that smart. I think I kind of admitted already that our first of year expectations, volume connected to price, volume was a little better than the price connection. I don’t have a magic milestone or goal posts for you out there. Jeremy Tonet Fair enough. Just one last one from me. As far the Noble payments around the splitter, I was just wondering for modeling purposes does that stop at a period of time, should we be taking that into consideration. Matt Meloy Yeah, it stops in the third quarter, partly through the third quarter. Jeremy Tonet Got you. And is there anything material that we should know just so we don’t overestimate there? Matt Meloy Yeah, good question. We haven’t’ given the specific number, so it’s going to be tough for you to triangulate. I will just say it’s not large enough so we had to disclose it as a dollar amount variance Joe Bob Perkins And we only disclose what we have to disclose as we put that out when we first – recognize we have confidentially – we’ve first of all good relationship with Noble and we have confidentiality requirements. Those confidentiality requirements say we disclose what we have to report and we spend a lot of time with accountants to make sure we got that right. Jeremy Tonet Fair enough. Makes sense. Thank you for the color. Operator Thank you. Our next question comes from the line of Schneur Gershuni of UBS. Your line is now open. Schneur Gershuni Hi, good morning, guys. I was wondering if we can expand on the integration process with Atlas a little bit. It sort of sounded like if I heard correctly that you might be seeing some very large capital efficiencies. I believe you said at one point that you’ve got a plant that you can start up and connect and so forth. I was wondering if you can sort of lay that out for us as to how that could possibly impact margins on a go-forward basis. Is there lot more opportunities like this where you can have capital efficiencies or I guess capital avoidance and start pickup volumes? Does your margins further expand with capacity utilization picking up? I was just sort of wondering if you can sort of expand on that a little bit for us. Matt Meloy I certainly understand the question. Five months have passed since we did the acquisition. Assets are terrific, particularly in the Permian Basin mix terrifically with our existing assets. People are working as one team, one target team for target bottom line. We did sort of give early conservative synergies to you all which makes you want more and I understand that. You’d like more detail, you’d liked the variance analysis against the plans. What’s really going on is we want to have a separate report of the progress on those synergies instead, the way we are managing it, the way we are working it, as those become embedded in our results. It’s one of the ways we’ve kind of outperformed our expectations and it will continue to be. You pointed to a couple of the factors and we alluded to them. When you combine those systems, you have capital efficiency opportunities, you have the opportunity that we’ve always had but even more so of getting gas to available capacity and we started up idle plants throughout our whole history, it’s just another opportunity to do so for the benefit of the combined system. Hope that’s helpful but I also know it’s not exactly what you wanted. Schneur Gershuni Maybe I’ll ask this a little differently. Classic analyst question, ex-commodity impacts, I mean the commodity is going to move up and down and so forth, but should we expect the IRR on capital deployed at least over the next six to nine months to be significantly higher than it has been in the past or so differently, should we see ex-commodity impact margins improve just as you’re able to take advantage of these capital opportunities, is that a fair way to be looking at it? Joe Bob Perkins I understand that question and it’s an easier question to address than the question from like last quarter, are your IRRs going to go down in this environment. In reality, when we’re working hard in this environment doing a lot of smaller projects taking advantage of the low hanging fruit, benefiting from takeaway gas with small expenditures, those returns are very attractive, okay, they’re very attractive, they need smaller dollar amount and that’s showing up in our bottom line. I like expanding on the answer to your question because it works against kind of hypothesis which is not, we’re not seeing as the case that our returns are going to go down. We may not be spending this larger chucks of dollars, which is good and proper in this environment to takes those and defer them until needed but the dollars we’re spending are getting attractive returns and I think that flows to our bottom line. Schneur Gershuni Okay, now that’s actually a great answer. As a follow-up to all the questions about your positive outlook with respect to the Permian, I think you started off by saying hey; we were surprised on the volume side, so therefore we’re sort of carrying it through and so forth. I was wondering if maybe you can expand a little bit as to why the volumes are outperforming expectations. Is it producers using better completions, are they targeting better wells or they’re drilling more wells than you initially thought and I was just wondering if you can sort of carry that through as to why the volumes have actually been performing better or not, if that’s a bad thing and as to why that will continue to be the case over the next six to nine months. Joe Bob Perkins First of all, kind of the last factor, it’s not because they’re drilling more wells than we thought, not appreciably to any extent. But it is a combination of some of the factors you mentioned and some others. I would start with their drilling with a more limited budget in the best spots and their technology has improved such that the best spots are more productive than they have been in the past. And those best spots are where our systems are and that to a great extent and that’s the reason for us having underestimated it. Maybe we’re too conservative, I’m not terribly surprised but it is a pleasant surprise on the margin for the volumes to be outperforming where the prices have been. Secondly, we have been successful because we are working hard, willing to selectively spent capital and have a very good reputation with customers out there that we’re winning packages of gas that are coming up for renegotiation on the margin. And strong competitors do that during tough times, those two factors maybe a little bit of when you have a little less activity and you’ve been working to catch up all along and get pressures down where you want them to be in the field that benefits our customers and it benefits us on volumes. Those are kind of the three areas that are in my head and it’s not because drilling was a lot higher. Schneur Gershuni So weaker competitors with poor balance sheets are basically at disadvantage, right relative to somebody like yourself, is that a fair way to think about the volume or market share comment. Joe Bob Perkins I think I had put it a little softer than that. It’s not just the balance sheet; it’s also the reputation for customer service. Schneur Gershuni Okay, great. Alright thank you very much, I really appreciate all the color. Operator Thank you. Our next question comes from the line of Michael Blum of Wells Fargo. Your line is now open. Michael Blum Hi, thanks, I’ll try to be brief here. Just curious for what you’re seeing from the impact of ethane rejection, is there has been any change in the way you’re running your plants? Joe Bob Perkins For running our plants, we’ve looked at that every day and we’re doing more not less ethane rejection where we can. Michael Blum Would you say that’s from what you see out there from other volumes that are coming to your system, is that sort of consistent? Joe Bob Perkins Yes, broadly so. We see a lot of pipelines as you know coming into our CBF fractionation facility. And certainly across the board you would characterize it as getting lower on ethane content meaning that more ethane is being rejected. Michael Blum Okay, great. And then, you gave some pretty good updates on the various projects that you have in the backlog or the potential backlog. So it is fair for me to just take away from that that effectively you’re still seeing pretty good demand for incremental projects, we haven’t seen any really material change which I think is something that a lot of people are thinking about. Joe Bob Perkins Our backlog is a list of those defined projects that people have seen in the permitting process or customers have talked about us working on for the most part. There is not a decrease demand for any of them, as we said really back to the first year; it’s a matter of when not if for almost all those projects. Increasing NGLs coming into Mont Belvieu continue, they’re coming a little bit slower than we might have expected in the early part of 2014 but demand is still there back to that, when, not if. Michael Blum And then, Matt I apologize if I had missed it, because I was writing quickly. Can you just repeat what was the Q2 ATM equity issuance? Matt Meloy Yeah, I said that in the script, I think it was $263 million and that also includes July, which I think I’d – it will be in our queue as a subsequent of that about $23 million or something. Michael Blum Okay, great. Thank you. Joe Bob Perkins That includes the GP stuff? Matt Meloy That was ATM, so the GP amount is a separate number we gave, which we also put in the queue. That’s why my number was so high. Operator Thank you. Our next question comes from the line of John Edwards of Credit Suisse. Your line is now open. John Edwards Yeah thanks for taking my questions. Back to the LPG export, just asking it a different way, I think you said there was a mix of spot and contracted, would it be fair to say the majority is contracted. Joe Bob Perkins [indiscernible] setting a record, I’m trying to drill down on that. I know that some of our competitors may give more details than we do on our export volumes and our mix of contracts, but we’re really making a competitive decision on how much we want to say for the good of our unit holders and the good of our shareholders. So I appreciate you drilling down but –. John Edwards Okay. Fair enough. Joe Bob Perkins If the mix is correct, there is a mix. Yes. Matt Meloy The thing I wanted to make sure we take away, as we have said the majority of our volumes are on contracted volumes, because I don’t want you to take away that the majority is short term or spot con. Joe Bob Perkins Sounded to me like we’re trying to figure out, if on the increment that was added what was the percentage of increment. John Edwards No, no, no, okay. Alright fair enough. And then just kind of extending some of the earlier questions asked but you have expressed optimism in 2016 based on the volumes that have materialized so far and I was just curious to what extend pricing might impact that optimism. If we stay in this sort of sustained price environment that we’re currently in rather than the improvement that a lot of people are calling for, I’m just wondering, how would that temper your optimism if at all, I mean, as perhaps people are responding to things based on price expectations going forward not the current sloppy environment that we’re in. Joe Bob Perkins Our feeling a bit better about the volume outlet for the remainder for the year and for 2016 is not based on looking at a single case or a single – it’s based on us looking at multiple forecasts related to multiple pricing and what we think is likely. The most important thing that we are communicating is that our volumes and our volume outlook at whatever price scenario we’re looking at has done better, it did better against the actuals, which actually were lower prices than we expected and going forward in price environment that’s flat for today, are volume feeling would be better than it was at the beginning of the year for that same price outlook. And if you get to the higher price outlooks, would have volumes greater than we expected for higher price outlooks. Does that make sense to you? Otherwise we’re trying to predict the prices and I’m not trying to predict the prices. Operator Thank you. Our next question comes from the line of [indiscernible]. Your line is now open. Unidentified Analyst Thank you. Congratulations on a good quarter in a tough market. If we could just continue on the volume question for just one second if I could because I haven’t pretty kind of addressed this and I understand your cautious outlook on volumes and you’re pleased with the way things came in but in terms of just a forward look, anyway to talk about what the weather impact for this quarter in terms of your volumes? Joe Bob Perkins This quarter’s weather impact was primarily a North Texas and we pointed to it because it was a fact in some of the producers in the area have pointed to it. It’s difficult to extract, we might have been flat quarter-to-quarter in North Texas if it weren’t for the weather impact, I don’t know that for a fact, I do know that I project where we are and where we’re going and it was appropriate to signal that unless there is some bump due to price, North Texas is likely to continue to decline not dramatically but continue to decline. When we said weather impact, it was not just the flood, it was the impact post flood on electricity connections even some washed out pipelines that took a while to repair primarily on the electricity side because they just didn’t have the cruise to take care of everything it wants and some of them more remote locations didn’t get taken care for a quite a while. Unidentified Analyst Thank you very much. On the terminaling and storage fees, there was some incremental, is there more to be reprised or is there any additional color you can give there? Matt Meloy I think that comment Joe Bob referred to is just an environment where you have some contango in the forward curves, as storage becomes worth more and there are some opportunities for additional income. Unidentified Analyst And then the last one from me, on your coastal plants, is there any outlook for idling any more plants there or shall we assume that’s done? Joe Bob Perkins The consolidation of the coastal straddle has been going for in many ways much of our career. We’ve said before that Target is well positioned to benefit from those consolidations. We have one of the strongest positions we like to call it a catcher’s mitt and as less efficient plants are idled we tend to capture a lot more than our share of the remaining gas and I just want to credit the people working the coastal gathering and processing for figuring out ways to save dollars make more money with less volumes get richer gas when it’s available and the producers are working to get richer gas. It’s a small part of our operating margin but boy did they work hard to keep that small part as high as possible. Unidentified Analyst Thanks very much. Operator Thank you. Our next question comes from the line Faisel Khan of Citigroup. Your line is now open. Faisel Khan Thanks its Faisel from Citigroup. Just a few questions from your press release, the condensate pricing were different quite substantially from field gathering from the coastal gathering systems and that difference was sort of wider in the quarter versus last quarter and even on a percentage basis versus last year. Can you kind of discuss what’s going on there, is that a quality differential, is that sort of a real transportation differential, it just seems a little bit wide even looking at WTI versus LLS [ph]? Joe Bob Perkins Yeah. Coastal is usually different than the field, it gets priced more of LLS, so if you look at the differentials from where we’re picking up that coastal of a field relative to the LLS which is typically a track closer to Brent. So it’s just those various differentials, I will say that the condensate does not have a big impact on our operating margins. So it’s not something that we focus a lot on. But it is due to this impact. Matt Meloy And occasionally there are quality differentials that might impact a single quarter. It’s – we market it the best we can, relative to supply and demand in the localized markets. Faisel Khan I’m just – because the differential has obviously narrowed in the quarter, so I just want to understand if maybe there is a constraint there, in the, I guess your field gathering system? Joe Bob Perkins No. I don’t have. I think we’re more talking about market dynamics than anything. Faisel Khan Okay. Fair enough. And then in your press release, you guys mentioned that the fractionation results were sort of impacted by lower system product gains, can you discuss exactly what that means, is that just you talking about rejecting ethane or you’re talking about sort of Joe Bob Perkins It really has more to do with our Mont Belvieu complex and volumes going through our fractionators. There are opportunities to blend the various products at the back of our fractionators before we sell those spec products to market, so there are pluses and minuses throughout the system and those amounts vary from quarter-to-quarter. Faisel Khan Okay. And then also you guys discuss in your results also lower refinery LPG supply, I would have thought with refiners sort of running all out in the quarter that LPG supply would have been up over the quarter, but because you’re talking about it being down, I didn’t sort of understand that dynamic too? Joe Bob Perkins I understand directionally what you’re describing, but what we always see in practice is about the time we think we’re going to be getting higher supplies from refineries, we don’t. It is pretty difficult to predict what we’re really good doing as managing it in the short term to do the best with what we get. There were some refining downtimes on the west coast, don’t really want to point or pick at any particular customer, but that shows up in our overall results. Faisel Khan Okay. So did you guys have access to the California refining LPG? Joe Bob Perkins Yeah. Some of those are our customers and what we also know on the margin is that not just pointing to West Coast, some refinery customers have actually used some of those products as fuel on the margin. So it’s a difficult trend to track, but we are as very opportunistic in adding that refinery services business to the overall propane wholesale marketing business. Faisel Khan Okay. And then last question from me, on your hedges, just want to make sure, is there a lag effect from the hedges or is it, as you guys show the volumes in the quarter, those volumes sort of are represented through your hedge contracts, I mean there is no difference from quarter to quarter, how to recognize that? Joe Bob Perkins No, there is no lag. The cash comes in for the month that we’ve had, we’ll recognize that as either income or we’ll put it as an addback in the cash flow statements to the extent the cash is received. Faisel Khan Okay, makes sense. Thanks for the time. Appreciate it. Operator Thank you. Our next question comes from the line of Chris Sighinolfi of Jefferies. Your line is now open. Corey Goldman Hey, guys. Corey Goldman for Chris. Just a quick question, sorry to go back to Noble really quick, what is the threshold, I had a curiosity for what you have to disclose? Joe Bob Perkins Sorry. Good try. I understand the question. I can’t answer, and by the way, absent the Noble contract, I’m not sure that I would get a concrete answer from our internal accountants or auditors anyway, they sort of know it when they get there and at some point, we say okay, I think I understand and we report accordingly. Corey Goldman Got it. And I guess just to dovetail in that, I’m assuming because you’re recognizing revenue before any things in the ground yet, do you assume the projects that go, just had a curiosity, what would be the impact to you guys positive or negative, if the project is a no go? Joe Bob Perkins I’m not prepared to discuss that either. What we said when we announced the deal is that relative to the original channel view splitter agreement, we were not economically disadvantaged by renegotiating the agreements and that’s all I can say. Corey Goldman Okay. That’s helpful. And then just the last question for me, and I apologize if I misunderstood what you said, I think you said with respect to contracts, you’re more contracted than non-contracted in the near term, that implies let’s call 3.25 between, just wondering how you compare that what you said last quarter about more than 4.2 million, is it 1 million barrels a month for ‘15 and then around 4.2 million a month in ‘16? Joe Bob Perkins Okay. Just to be clear, we didn’t say, we said more which is greater than half, so we’re not saying we’re more or less in that previous number that we gave, we just said we’re not going to kind of get in to the dialing in the exact amount that we’re contracted in the exact amount of spot. So I wouldn’t read from that that we’re less. Corey Goldman Okay. So you can’t reiterate if you’re in line with the 4.2 million about a month in 15? Joe Bob Perkins Oh, I could but I’m not going to. Corey Goldman Okay. I appreciate it. Operator Thank you. Our next question comes from the line of Gregg Brody of Bank of America Merrill Lynch. Your line is now open. Gregg Brody Hi guys. Just a quick one for you. I think you mentioned when you gave your hedge numbers for the NGLs that you were 80% hedged in ‘16, versus 30% for the rest of this year, did I hear that right and if I did, what’s the…? Joe Bob Perkins No, we’re not 80% hedged, I think for ‘16 for NGLs, I think I said 15%. Gregg Brody 15, then that would explain what I misheard, that’s perfect. Thank you, guys. Operator Thank you. Our next question comes from the line of [indiscernible] of Citadel. Your line is now open. Jeff Mccarter Hey, guys. This is Jeff Mccarter with Citadel. I was hoping you could elaborate a little bit on the point you made about transitioning packages of gas, what basins are you seeing those in and were there further opportunities? Joe Bob Perkins Okay. You may have interpreted transitioning from a term I used as takeaway, kind of going back, mostly, we’re finding volume increases from our dedicated contracts with existing producers and those volumes were better than we thought in our important basins, battling on the entire Permian basin. West, south, surprised us to the positive. Particularly those large Permian basin positions in bad lands are coming from our existing acreage, but across the board, we’ve also been successful and that’s a complement to our people of winning a whole lot more, many, many more deals and much, much more volume on takeaway than we have lost, takeaway being a contract came up for renewal with someone else and we got it. Now, that’s on the margin, it’s a positive on the margin. It’s part of the positive surprise, but I don’t have more information to provide you other than to say we track it by deal and track it by volume and report back to our board and the wins are a whole lot better than the losses. But mostly, the positive volume surprised us from our existing contracts and our existing dedications. Jeff Mccarter Okay. So no real color that you can offer on, is that part of what drove the Eagle Ford volumes or is it producers shifting to different processors in the Permian, nothing more you can offer? Joe Bob Perkins I will say that my win loss ratio on volumes or deals is weighed to the target side on every basin. Operator Thank you. Our next question comes from the line of Ethan Bellamy of Baird. Your line is now open. Ethan Bellamy Bob, how would you handicap the potential for elimination of the crude oil export band and if that occurred, what would that be to your strategy? Joe Bob Perkins Everybody frowned at me, because they were afraid I would start talking. Ethan Bellamy I’d love to hear you do that. Joe Bob Perkins I won’t, I don’t handicap anything moving fast in Washington if it were to happen, we’re always trying to help as a midstream player. Everybody just did a big sigh of relief, I think that’s as much as I can dig in to. Ethan Bellamy So just to follow up there, how does that potential outcome factor in to your risk analysis on things like the condensate infrastructure and the agreement with Noble? Joe Bob Perkins That question, I can’t address. Recognizing even with export bands or opening up condensate, you still have needs for particular assets. Student body won’t go right or left based on a change in the law and our customers with their contracts and their portfolio of opportunities will decide whether those investments continue to make sense. That’s what we’ll respond to. And absent near term moves in Congress, that’s impacting people’s longer term outlook about assets. Even with the opening of selected condensate exports, you continue to need splitters on the US Gulf Coast to some extent within refineries, outside refineries, whereas going to splitters on the other side of the water. Where is the best place to be importing products, and moving it around, that’s a global, it’s a global market with lots of solutions. Ethan Bellamy Thanks so much. I guess I’m asking the right questions if you tell me no. Joe Bob Perkins I’m going to get a bad reputation. I’ve really tried to answer all the questions. We can only answer some of them so much. Operator Thank you. And our next question comes from the line of Charles Marshall of Capital One Securities. Your line is now open. Charles Marshall Two quick follow-up on your opening comments regarding distribution growth for the year, expected to come in at the lower end of the range, given your sort of better expectations on the back half of the year and field GMP volumes, et cetera, is your guidance range at the low-end, that includes your updated forecast for the remainder of the year or could that slide more to the right on the higher end of the range. Matt Meloy NO, we took in to consideration both our outlook in the field and our logistics and marketing business in to that 4 to 7% and then towards the lower end of that, we’re also part way through the year, we had a distribution increase of a penny in the first quarter, and then half a penny in the second. So then, we’re part way through the year, so we have a better handle on just kind of how the average is going to shake out. Joe Bob Perkins And we try to drive it smoothly. Charles Marshall Okay. I appreciate that. One last quick one. Regarding potential ethane export projects, is there any update there you can provide for us? Joe Bob Perkins No update. Charles Marshall Okay, thanks. Operator Thank you. And I’m showing no further questions at this time. I’d like to hand the call back over to Joe Bob Perkins for any closing remarks. Joe Bob Perkins Thank you, operator. Thank you everybody for your patience and your interest and to the extent you have any follow-up questions, please feel free to contact Jim, Matt or any of us. Good day. Operator Ladies and gentlemen, thank you for participating in today’s conference. That does conclude today’s program. You may all disconnect. Have a great day everyone.

Companhia Paranaense de Energia’s (ELP) CEO Luiz Fernando Leone Vianna on Q1 2015 Results – Earnings Call Transcript

Companhia Paranaense de Energia (COPEL) (NYSE: ELP ) Q1 2015 Earnings Conference Call May 15, 2015 02:00 PM ET Executives Luiz Fernando Leone Vianna – CEO Luiz Eduardo da Veiga Sebastiani – CFO and IRO Sergio Luiz Lamy – CEO of Copel G&T Vlademir Santo Daleffe – CEO of Copel Distribuição Analysts Vinicius Canheu – UBS Operator Good afternoon, thank you for standing-by. Welcome to Companhia Paranaense de Energia Copel’s Conference Call to Present the Earnings of the First Quarter 2015. We’d like to inform you that all participants will be in a listen-only mode during the company’s presentation. Afterwards there will be a question-and-answer session, when further instructions will be given. [Operator Instructions]. Before proceeding, let’s us mention that any statements that may be made during this conference call related to Copel’s business prospects, operating and financial projections and goals, beliefs and assumptions of the company’s management and the information currently available. Forward-looking statements are no guarantee of performance. They involve risks, uncertainties and assumptions because they relate to future events, and therefore depend on circumstances that may occur or not. General economic conditions, industry conditions and other operating factors may also affect the future results of Copel and these results that differ materially from those expressed in such forward-looking statements. Today with us we have Mr. Luiz Fernando Leone Vianna, CEO of the Company; and Mr. Luiz Eduardo da Veiga Sebastiani, CFO and IR Officer; Mr. Marcos Domakoski, Chief Corporate Management Officer; Mr. Cristiano Hotz, Institutional Relations Officer; Sergio Luiz Lamy, CEO of Copel G&T; Mr. Ricardo Goldani Dosso, CEO of Copel Renováveis; and Mr. Reinhold Stephanes, CEO of Copel Participações. The presentation will be delivered by the Company’s management, may be followed at the Company’s website at www.Copel.com/ir. Now I’ll give the floor to Mr. Luiz Fernando Vianna, CEO of the Company. Luiz Fernando Leone Vianna Good afternoon. I have my management friends here with me. Welcome to the conference call to discuss the earnings of the first quarter of 2015. I would like to begin by giving you a backdrop of the first months of the year which was quite challenging. [Technical Difficulty] that we’re drilling [Technical Difficulty]. On the one hand unfavorable hydrological scenarios including discussions are always progressing. On the other hand we have the implementation of [clients] and the so called tariff [indiscernible] was brought significant adjustment to energy carriers expecting inflation rate and causing even more turmoil in an economy that is already stagnating. In mid-May the scenario is markedly more optimistic compared to past month. Rainfall in March and also in April mitigated the risk of rationing and [indiscernible] and adjustment have allowed distribution companies to stand on their own. However, even though energy rationing is no longer an imminent risk in 2015, our reservoir remain low which takes the operation of TPP and the deficit of hydraulic generation or the so called GSF will remain high negatively affecting generation companies that produce hydropower which are exposed to COP or different settlement price which should remain at maximum levels all year round. In addition it’s important to remember the economic conjunction combined with increase in energy tariffs and awareness campaigns mainly through stagnation or even a drop in energy use. This shown by EPE data which points to a drop of 0.6% already in the first quarter of 2015. However despite this adverse scenario, consumption of energy in the captive market of Copel Distribuição increased 1.7% in the first quarter and latest information show that this continues growing until mid-May. In terms of results our income totaled R$470 million in the first quarter 19% lower than the income in the same period of the previous year. EBITDA posted a drop of 3% totaling R$835 million this quarter. Energy cost significantly increased by 82% which is a result of higher prices in auction and the end of the transfer policy of CTE and ATR account fund which offset a significant portion of this expense last year. On the other hand we have a 44% growth in our revenue in an acquisitive sale to final consumers this stems from adjustment applied in Copel Distribution tariffs required to offset the increase in the energy costs. Next we’ll be breaking down the numbers, but before that it’s important to say that the beginning of 2015 was marked by important sector of discussions involving the company, associations, regulatory agencies and the government. We are now more proactive now in the bank, topics like reversion of energy cost, indemnification of assets and renewal of distribution positions but we also have important discussions involving the current performance of construction works in terms of intake of the majority of companies with construction projects in Brazil we do have this it’s important to make some comments on construction works on Colíder Plant. As you can see on slide number four, we are requesting with them now a waiver of liability a term of over 644 days related to the delay in the startup of Colíder Plant. Initially it was scheduled for December 30, 2014. But after the waiver start-up will be scheduled for October 2016, this request is justified because over construction works we have acts of vandalism in the facilities and strikes that interfered in our schedule which was also affected by changes to the original design and a delay in the issue of the environmental license required to begin this vegetation suppression of the reservoir area. We’re still awaiting for the waiver of liability to be accrued by now but we are in compliance with the contract of Colíder Plant which total 135 average megawatts using part of our non-contracted energies from other plants. Still about Colíder it’s important to say that our current forecast is to have construction works completed by April 2016. Another highlight is indemnification of pre-existing assets in May 31 year 2000 in late March we submitted to an evaluation report showing indemnification amount of R$882 million on December 31, 2012. The book value of these assets was 160 million on the same date. This difference is due to the methodology of the newest latest management value which was used according to [indiscernible]. Please bear in mind that the final indemnification amount will only be set once amount evaluates the provisions submitted which is expected to happen by year end. On slide number five I would like to underscore the start-up of [indiscernible] lines. By year end we expect to have an increase of 135 million in the revenue or position assets with a start-up of other important assets that are now in the final construction phase. In addition we also have a commercial startup of wind farms [Santa Maria] with a joint installed capacity of 59 megawatts. With that Copel [indiscernible] already has 153 megawatts of wind power in commercial operations. In the coming months another 177 megawatts will be added to our generation farm. Commercial start-up of another five wind farms in [indiscernible] complex and four farms up [indiscernible] complex in which we own a 49% stake. In addition we have 13 wind farms under construction in [indiscernible] complex totaling 332 megawatts of capacity to be added by 2019. Copel has is already among the largest companies in this sector in Brazil. Now I give the floor to Luiz Eduardo da Veiga Sebastiani our CEO and IR Officer. He will be giving you more detail of the results of the period. Luiz Eduardo da Veiga Sebastiani Thank you CEO, Luiz Fernando Vianna. I also thank the president of CEO of Copel subsidiaries with us progression on from the finance area and other staff at Copel and specifically those who are joining us through the conference call, analysts, investors a very important moment for Copel, it’s important to declare the investors. I would like to begin by making comments on the good result of [indiscernible] with income total R$155 in the first quarter of 2015 16% above the numbers year on year. Just reminding you of the [indiscernible] as you can see Slide 6, the TPP is once again operated by UEG Araucária a Copel subsidiary, this operation came back in February 2014, it is a trend under the merchant model with no availability contract and sold only energy produced in this spot market and the selling price is between POD and TBU whichever is higher according to the rules of this operation modality. Last year the TPP traded energy according to PLV since it was higher than CVU during most of the rest of year; however, in 2015 with a drop of PLV cap to 388 megawatts per hour, the energy sales price would always be CVU which was defined by Aneel as follows. R$765 per megawatt per hour between February 1st and May 30th and R$595 per megawatt per hour between June 1st and January 31, 2016, CVU is higher because in addition to gas cost recovery it also includes recovery of administrative and operating cost in addition to asset compensation despite the growth in the sales price vis-à-vis 2014 the plan provided very interesting results in the first quarter reaching an EBITDA R$239 which accounts for an increase of 43% year-over-year. This result is mostly due to the fact that the TPP operates continuously in the first three months of the year with a total of 963 gigawatts per hour whereas last year the plant only came to well responsibly in February. Now Copel consolidated results on Slide number 7, operating results, operating revenue went up 39% in the first quarter of 2015 exceeding R$4.2 billion within drivers for growth in revenue were increase of 44% in the revenue of electricity sales to final consumers mainly due to adjustment applied to tariff by Copel Distribuição 24.86% in June 2014, our annual terrific adjustment and 36.79% in March this year due to the Extraordinary Tariff Review in addition to growth in the captive market, 17% growth in the account electric energy supply starting from higher revenue in CCEE due to the sale of energy from Araucária as per the dimension and the strategy of energy allocation in the spot market by Copel GeT, we allocated 1,522 gigawatts per hour this quarter vis-à-vis 501 gigawatts per hour in the first quarter of last year, very significant growth. As per the availability of the power grid which is made up GUSP we had an increase 7% due to the annual APL adjustment and new start up in the transmission segment. Please note that the adjustment in the GUSP was offset by charges this quarter as well the revenues which includes in addition for sectoral asset and liability results other revenues like construction, telecom and gas reached likely more than R$1 billion reflects of the recognition on R$561 million related to the result of sectoral financial asset and liability and the 17% growth in telecommunications revenue which totaled R$48 million marked basically about sectoral assets and liabilities result in Copel Distribuição we highlight that this revenue stands for the increase and the asset balance related to tariff deferral and higher cost of energy in charges which will be recovered in the next tariff review. These central assets were not recognized in the balance sheet since the adoption of IFRS and are now being posted again after an addendum to the concession contract we signed with a guarantee that residual value of portion A and other financial components not recovered by a tariff will be included in the indemnification calculation, should concession be terminated. On the next slide we talk about operating cost and expenses in the first quarter reaching 3.6 billion or 50% higher than the first quarter of 2014. This is mostly due to the increase of 82% with electric energy particularly sale totaling R$1.8 billion this quarter. Costs with charges and the use of the grid increased 61% basically due to higher charges in the sales of service related to terminal dispatch in addition to an increase of cost related to the startup of new license in the system and adjustment in concession carried n Itapúa energy. Cost with the approaches increased 11.4% vis-a-vis the first quarter of 2014 it’s a natural consequence of [Araucaria] plant which is now being operated by UEGA, UEGA only as of February, 2014. Managerial cost increased 22% reflecting higher expenses with personnel and third-party services, inflation, adjustments and salaries, benefits and contract cost required to offset the growth of the company and also GeT and EFC. Costs were also affected by an increase in provision for several administrative and work, labor claims in addition to the closing of R$73 million in ADA and the price of energy traded in CCEAR in Colíder and PLD. On slide number nine we break down expenses with energy purchase for retail like we said before increased 82% totaling approximately R$1.8 billion in the first quarter of this year. Energy purchase in the regulated market CGAR increased basically due to the entry of new contracts and high prices. Copel Distribuição purchased 302 average megawatt at price of R$385 per megawatt per hour in the adjustment option in January this year in addition to repayment of contracts by inflation and high dispatch of thermal plant this quarter. [indiscernible] cost doubled vis-à-vis the first quarter of last year reflecting the tariff adjustment denominated in dollars but the main reason behind the increase in the quarters competitive cost is the end of the fund transfer policy from CDE and account ACR. The first quarter 2014 had 832 million with CDE and ACR account to offset high cost at that time. Slide 10 shows that our consolidated EBITDA had a growth of 3% vis-à-vis the first quarter of 2014 totaling R$835 million with the margin of 2% of operating revenues. Copel G&T cash generation accounted for 75% of consolidated EBITDA, Copel Distribuição 6% and Copel Telecom 3%. The remaining companies of the group jointly account for 16% and the major contribution came from other Colíder Plant and to the EBITDA margin Copel G&T closed the first quarter with a margin of 69%, distribution 2% and telecom 45%. On slide 11 we show Copel’s consolidated net income. 470 million in the first quarter of 2015 19% lower than the same period of 2014 while we analyze subsidiary results we can see Copel distribution close the first quarter with a total income of R$29 million offsetting the launch in the same period of the previous year. Copel G&T closed the quarter with the income of R$409 million or 5.3% lower year-on-year attracted by higher GSF and a reduction in PLV cap. Copel Telecom in turn had an income of R$15 million in line with the numbers year-on-year. These were our highlights and we are happy now to take questions. We are here for any questions you may have. Thank you very much. Question-and-Answer Session Operator We begin now the question-and-answer session. [Operator Instructions] The first question is from [indiscernible] Citigroup. Unidentified Analyst Good afternoon everyone. Thank you for the call. What about Colíder’s product? Do you have any forecast when the waver will be evaluated by the regulatory agencies? Unidentified Company Representative Let`s turn to Sergio Lamy, Engineer and CEO of Copel G&T Sergio Luiz Lamy Good afternoon. To answer your question — we have a preliminary statement of a technical note an internal technical note by now 214 days of waivers. With 214 days which would account to slightly more than six months or seven months actually this is what the number that we used last year — this is when we first decided to have the impairment of Colíder plant. At that time we base ourselves in an internal document given signs of — request of five months. Although this new statement is not favorable compared to the original one we are not happy at Copel with such a statement. We’ve been working with a regulator in order to try and clarify the issue so we can be closer so the position we understand to be fair and certainly issued exceed one year. Today the delay of the plant is around one year and four months. And we are very confident that we do have arguments enough in order to have the waiver of liabilities very close to the real delay of our operations. Operator [Operator Instructions] The next question is from Vinicius Canheu from UBS. Please go ahead. Vinicius Canheu Good afternoon. Thank you for the call. The question is still about Colíder. I would like to have more detail on the negotiation of the purchase of equipment and turbines that you have with wind power Energia were there any energy or cost increase? Vlademir Santo Daleffe This is Vlademir speaking again from Copel GMP the answer is no. When it comes to an increase in cost, we haven’t had any cost increase yet. We haven’t identified any problems. Any signs of problem were related to a risk of acceptance vis-a-vis new project but this risk is very well under control today vis-a-vis new all the measures we took supported by the consortium in order to carry out a diagnosis of the whole supply all the services that are being outsourced by WPE. So we can start managing directly our supply with our suppliers. In addition we also had another approach in the product supply that is in Mendoza, Argentina. The idea is also to present problems and the schedule in addition to what we already had caused by environmental factors. So just to conclude, there used to be a risk that might affect the scheduled but the risk is very much mitigated and we have no signs of an increase in CapEx caused by the problem with WPE. Vinicius Canheu Could you make some comments about the negotiation of the use of Petrobras infrastructure for gas supply to automatically what will the comps in wells be like? Unidentified Company Representative We don’t have accurate information yet. We’re still working on it with UEGA and Petrobras. We don’t have any data yet. And gas supply for Araucaria TPP number 2 has not been defined yet. One possibility is supplied by Petrobras. But, we can also work with imports, imported gas, and maybe have a plant, a gasification plant along the coast of Parana State. But, this has not been defined yet. We are still in the phase of very preliminary studies. Operator [Operator Instructions] The next question is from [Pedro] from Credit Suisse. Unidentified Analyst Good afternoon. My question is about Araucaria could you give us some color about Araucaria’s current cash cost and what is the forecast over the year of this cash cost, any variation expected? Unidentified Company Representative Cash cost I don’t have it here with me but the forecast is at best a very stable scenario only around our expectation is to maintain this batch. So let me just correct myself there will be a slight impact in the coming months like we said before in our presentation when Mr. Vianna delivered a presentation he mentioned reduction of CVU so there will be a slight reduction due to CVU reduction in the coming months, but that in the second half of the year, I don’t have the percentage with me but reduction would not be significant I would say 15% max. Unidentified Analyst We are saving ourselves on the total cost at Araucária this quarter; could you try to assume the cost of operating Araucária per megawatt per hour? 100 megawatt per hour per CVU assume May IRR 7.65 that’s why Araucária is so significant over the year, I understand there will be a drop into the use 595. But would like to understand give the confident of Araucária the bulk is gas operation should we consider for 100 megawatt per hour and then there will be a reduction in EBITDA at Araucária this year, but something very interesting still interesting to the Company. I will just like to understand if the math is okay or if I am missing something. Unidentified Company Representative Your math is correct but when it comes to cash price variation, that’s a market issue. We can make projections but this is uncertain. Right now I cannot make any more accurate forecast. Unidentified Analyst So if there is any significant variation that in the cost of Araucária, can you also knock on an outdoor to ask for a CVU review? Unidentified Company Representative Absolutely, we are assuming that in the CVU of 7 of 5 and then 595 maybe we have some question of EBITDA per megawatt per hour for Araucária this year. No [indiscernible] when it comes to CVU recognition. There is no question. Unidentified Analyst But is there is any significant variation in cost? Unidentified Company Representative Yes, maybe become higher. There is no problem, no difficulty to try to file or request a CVU review. Operator [Operator Instructions] The next question [indiscernible] Bank. Unidentified Analyst I would like know your viewpoint about concession renewals for distribution companies. How do you see that and what is the impact on Copel in terms of any possible obligation, could you give us some color? Unidentified Company Representative I’ll ask [Akaishi] our engineer from Copel Distribuição to answer your question. Unidentified Company Representative We are convinced that the review of the concession agreement of distribution when it comes to Copel, this is well balanced. We have a schedule already set in the issue of the creative hours of public hearings to validate at least conditions that were stated by media. And as we see it at Copel, when it comes to these conditions there will be no problem to work on obligations that must be related to this concession agreement. Unidentified Analyst Okay, thank you, if I may I would just like to ask another question, I would like to better understand why management cost increased so much? I understand was an increasing thermal dispatch in some cases but still even personnel expenses increased more than 10% just define you and what should I expect going forward? Unidentified Company Representative More specifically at the distribution company when it comes to personnel, we had 11% close to 11%. If we consider that we really have an adjustment at salary adjustment then in from IPCA restatement, it’s totaled 7.5%. The variation was about 4% on top of what is our obligation according to labor agreement. Naturally, if you noted that over 2014, we had a lag in GEC indicator, we were concerned about recovering it and one of the actions was to work again in our labor force in several point in which GEC really had an impact and then we really had an increase in fact and also in places or regions where we had to re-contract and maintenance services to be outsourced. And specific points because as you know, distribution is state wide and in order to shorten this layoff we had to increase our personnel. In the first quarter in addition to this effort to try and shorten our connection and our layoffs we also had a strong impact a weathering effect that were atypical from January to March over these months we really had to work on an extraordinary basis with our headcount. So it also is related to operating cost. If you look at it carefully this effort when it comes to strategy, this effort met our expectations because duration index within the [indiscernible] by the regulatory power and now we feel comfortable to meet the terms of the concession agreements without running any risk due to extension. Operator The next question is from [indiscernible] from JPMorgan. Please go ahead, sir. Unidentified Analyst Good afternoon. I have two questions. The first question is about [indiscernible] in June. Do you have an idea about adjustment index that you want request it now and do you expect to include the tariff deferral for 12 months, you have about 1 billion deferred over 12 months, is that the intention? Then the second question is about [indiscernible]. You consider Copel participated in a consortium with energy in [2012] and that is walked out of the process. We know there will be a privatization by rent and then we have inner progress disclosed. We’re interesting in this kind of concession with the clients, so are you having to look at these items, are there any strategies or any partner that you consider with another private player. Thank you. Unidentified Company Representative Your first question just would be, okay, it’s about tariff reveals, okay, engineer [indiscernible] is going to answer your question. Unidentified Company Representative The extraordinary tariff review recovered on global terms portion A. So our expectation which will be included in our calculation usually are submitted to announce on the eve of the basis of adjustment in exactly the factor you mentioned which are the deferrals that happen over 2013 and 2014. This is our expectation and once this is included again we believe that distribution company will be well balanced considering the current scenario that basically has an impact on tariff. As to the scenario mentioned about any possible interest or sale of distribution companies right now by Copel there is no attention given to this aspect. Attention is given to Copel Distribuição. We work on efficiency in this area at Copel Distribuição and in all the other aspects that are under Copel responsibility this is where we focused our attention and dedication of Copel’s whole professional team. So in 2013 we considered the growth rate but we also walk away for it and like we said before now we are paying attention to our distribution assets for Copel. If I move after the comments we obtained keen attention now to the rules of the extension and naturally based on the rules of the extensions rules to set, there might be opportunities or not but it’s still too early to carry out any analysis, the main point today is the extension of the contracts from 2015 to 2017. We already have a definition if renewal should be for 20 or 25 years. Do you know that already, this will be defined through a decree law that possibly will be issued in the second half of the week announced by the Ministry of Mines and Energies and we believe that decree law will these topics. And third what really prevailed in this loss, so they specified 30 years. So we expect to see a decree loss about distribution companies and also a public hearing to be set by Aneel. Operator This concludes the question-and-answer session. I give the floor now to Mr. Luiz Eduardo da Veiga Sebastiani. Luiz Eduardo da Veiga Sebastiani Once again I would like to thank you all and wish you a great afternoon, a great weekend I ask all Copel’s team of professionals and those of you who joined our conference. We are relentlessly trying to be more efficient so our company Copel can reach even higher levels. Thank you very much. See you in our next conference call. Operator This concludes Copel’s conference call. Thank you all for joining us. Have a good afternoon. 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