Tag Archives: economics

GreenHunter Resources’ (GRH) CEO Gary Evans on Q2 2015 Results – Earnings Call Transcript

GreenHunter Resources, Inc. (NYSEMKT: GRH ) Q2 2015 Earnings Conference Call August 14, 2015 10:00 AM ET Executives Gary Evans – Chairman and CEO Serene Prat – Head of IR Kirk Trosclair – EVP and COO Ronald McClung – CFO Analysts Operator Good morning. My name is Kamey and I will be your conference operator today. At this time, I would like to welcome everyone to the GreenHunter Resources Second Quarter 2015 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Gary Evans, you may begin your conference. Gary Evans Thank you, operator and thank all of you for dialing in today. My name is Gary Evans, I’m Chairman and CEO of GreenHunter Resources and Magnum Hunter and again with me here, Kirk Trosclair our Executive Vice President and Chief Operating Officer as well as Ron McClung, our Chief Financial Officer. And before we get into the meat of the discussion today to talk about our second quarter and six months ended June 30, 2015 financial operating results, we need to let our listeners have a little forward-looking statement. So Serene Prat our Head of Investor Relations, is going to read that for us. Serene? Serene Prat Thank you. Before we begin with the content of today’s call, I’d like to advice you that Safe Harbor include forward-looking statements within the meanings of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The following discussion provides information, which management believes is relevant to an assessment and understanding of our financial condition and results of operations. The discussion contains forward-looking statements that involve risk and uncertainties that may include statements regarding our expectation, beliefs and intentions, or strategies regarding the future. Actual events or results may differ materially from those indicated in such forward-looking statements. This discussion should be understood in conjunction with the financial statements accompanying notes and risk factors included in our SEC filings. The discussion should not be construed to imply that results contained herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by our management. Actual events or results may differ materially from those indicated in such forward-looking statements. This disclaimer is an effect for the duration of this conference call. Gary Evans Thank you — that was outstanding. Let’s now get started with respect to the call today. We filed our quarterly financial statement press release earlier this morning. So, hopefully, you received that. And I thought before we got into the specifics about the company and its operations for the quarter, I might talk a little bit about the macro picture that we’re all experiencing in the energy industry today and how it affects or doesn’t affect GreenHunter. So, as many of you know that are involved in energy arena, we had a change with respect to OPEC’s decision to basically flood the world market with oil beginning around Thanksgiving and that we’ve experienced a precipitous decline in crude oil prices worldwide from around $100, $105 a barrel down to in the $42 a barrel day range today. The purpose of doing this is to regain market share that OPEC lost due to the significant success that independent oil and gas companies have had in the shale plays here in the United States over the last five years. And so, it’s had a dramatic effect in the entire energy industry has called the rig count to the cut significantly down to historically low levels and is creating a huge amount of layoffs and just basically a much reduced capital spending level by all energy independence. People are in a preservation of capital mode not knowing how long these lower prices will persist. It’s also had an affect with respect to natural gas prices which is really, we’re more involved with respect to the Marcellus and Utica plays that we typically handle most of our water with up in the Appalachian Basin. The gas prices are down about $1 to $1.50 from where they were a year ago and that has also created a slowdown in drilling activity in our region not as much as other parts of the country but it’s definitely impacted it. So, we continue to stay busy but not as busy as we want to be, that’s causes to have to work a who lot harder get new accounts, we feel real good about some new prospects that we’re working on and our ability to continue to keep our wells full and we believe that this part of the country being the Marcellus and Utica in the south, West Virginia, Southeast Ohio will continue to garner a significant amount of capital. So, there is any place in the country I would rather be its this area, there is no other play I want to be active in. We continue to have the best margins, we continue to have the lion’s share of the business. And we continue to add capacity to allow us to gather and inject greater volumes of water going forward. So we’re going giving you a lot more detail as to some of this today. One thing that’s very important for you to understand Magnum Hunter has announced as of about a week ago that we have entered into a letter of intent for $430 million drilling program over in Ohio which encompasses about 50 Utica wells, that program will began in October. And GreenHunter will have a 100% of the water business there. So, while we’re having a little slack here over the next last few months and we’re continuing to fill our wells, there’s going to be a whole slug of new activity and that activity will continue for about two years. So, because of the [sister] relationship between Magnum and Green that’s going to definitely benefit GreenHunter going forward and there is more details on that if you want to look at the filings that Magnum has made publically over the past week and many analyst research reports have been written about that as well. So, with that I’m going to turn the call over to Kirk — give you specific details of our activities during the second quarter and update you on what we are working on. Kirk? Kirk Trosclair Thanks, Gary. Before we going to the specifics, I do want to add a couple of comments on the numbers in Appalachian as it relates to volumes and trucking hours and things like that across our portfolio. First the rig count decline since 2014 in Appalachia has decreased 42% in Utica and 21% in the Marcellus. The keyword across all the presentations that we’re listening to from all the E&P companies is efficiencies and efficiencies translate to price reductions across the entire service industry as it relates to service providers in the oil and gas business. The effective lower total rig count, basically equals significant reductions in flow back volumes and a slightly less, lower production volumes across the board with the most being significant reductions from flow back. Secondly the E&P capital expenditures that Gary mentioned earlier were lowered again in the second quarter and companies were voluntarily asking service companies to help by reducing rates to match the falling commodity prices. We feel that these have now hit the bottom across our industry in the Appalachia region and we should be able to maintain from here on out. On appositive side, as he mention with the Magnum Hunter JV, GreenHunter has strategic alliances with certain operators in the Appalachian Basin that will help curtail some of the overall effects of the downturn in the industry and the increased flow back volumes just from that JV and the production volumes that will come from it will help the company tremendously going forward. We probably won’t realize those affect into the GreenHunter side from flow backs to the latter part of fourth quarter of this year but we’ll see significant increases starting in the first quarter of 2016. So, what does it mean for GreenHunter for the remainder 2015, we’ll continue to fight the fight, manage our expenses and start to gain additional market share, something we haven’t — have not had to do in the past. We’re having to go out and grab new market share, enhance some operating efficiencies and be the best service provider of Oilfield Fluid Management Solutions in the industry. Our team in Appalachia has done a great job through this downturn and they are to be commended for it. So to get you to the specifics of the second quarter, on July 27, you guys remember we sent out a press release and we turned on two new disposal wells at our Mills Hunter facility located in Southeastern Ohio. These wells were — we were pleasantly surprised at some of the increased rates we had once we turned the wells on, our initial injection rates told us we were going to 3,000 to 4,000 barrels per day and with the combined two wells, we think we can push the 8,000 barrels per day limit on these two wells. The increased injection capacity basically takes our overall capacity of the company and increase it by 50% and takes us to 21,000 barrel, so permitted injection capacity. Just recently, we added some additional trucks in the latter part of July, I think it was like the last day of July our self, we took the delivery of two new Peterbilts, we sent those to the shop in West Virginia to have the 407 tanks put on the trucks and we just recently as of two days ago received four additional trucks at the shop and those are being outfitted to haul condensate and water by having those sets to DOT 407 related trucks. We plan to have the two that were in the shop first out to the out on the street and actually hauling in the next couple of weeks and then the other four will probably be two to four weeks behind as they continue to come out the shop and then that will leave us with two remaining trucks from the user proceeds from our senior lenders. And those will hit sometime in October. Some of the things to point out that we continue to improve our operating margins on quarter by quarter basis, we’re getting a lot better at doing our business in the Appalachia region and we’ve increased those from 38% in the second quarter 2014 to 49% in the second quarter of 2015. The other thing that we need to point out and it’s really is our internal trucking, we mentioned this in our first quarter call, we learned a lot by hiring third party transporters and trying to grab volumes from additional trucking companies and running it through our own services but that was not beneficial to the company and we’ve learned to utilize our own internal trucking and those numbers have jumped dramatically from 18% of second quarter of last year to 40% in second quarter of this year. Now, of course some of that has to do with fuel pricing and things like that but our overall expenses in-house for the operations for these units has gone down. Also, at the unit in these times of tough commodity prices we’re cutting back, we’re running a lean shop here and we’ve decreased that by 1.6 million and total decrease of 21% and something that we’re very proud of, we’ve produced positive adjusted EBITDA for the first and the second quarter of 2015 and the second quarter at 316,000 of the positive EBITDA here in house. So, those are some of like the key highlights of what happened in the second quarter, obviously we have a lot of things that came out and we’ve been working on in the third quarter, we were delayed on a lot of this construction efforts for some new wells, you can see in the press release, we spoke about what contributed to those, some of it was the funding delay initially, then it was permitting and new processes and things like that that’s going on with the Ohio department of natural resources and on the West Virginia side with the [environmental] protection. It’s a new ballgame out there, which is not a bad thing for us, we’re complying with all the rules and rigs which we always have and we’re going to be a leader in that industry and learn from the past in how things transition to new rigs and responsibilities and we’ll get more efficient at that. The last couple of years — permitting of a new well would take us 45 to 50 days, now that’s gone up to about six months, we think we can get that timeframe down in the four to five month range but that will be the new norm from here going forward. So, that was some of the delays that we had at the mills Hunter facility, we’re nearing completion of that, we should have the third of the four wells additionally that we’re tuning on at mills here in next 30 to 45 days, we should begin injection into that well and then the final well which is the furthest well away from the pumping facility, will probably come online sometime in late October. I know you guys mentioned the Ritchie Hunter 2 which is the West Virginia well that we have ready to go. The well itself, the facility, the flow line everything is completed, we’re just waiting the final approval from the West Virginia Department of Environmental Protection and that’s impressive, we met with those guys at their office in Charleston two weeks ago and we should receive that final permit here in the next 30 to 45 days. So, that’s kind of the operational highlights of what’s been going in Appalachia, with that I’ll turn over to more details through Ron McClung on the financials. Ronald McClung Well, as both Gary and Kirk have said, it’s been a tough environment in the second quarter in terms of people have stopped drilling as much, flow back and so forth so, we’ve had a corresponding decrease in the revenues, a year ago our revenue in total was 6.8 million or second quarter in this year was 4.6 million. Our two main sources of revenue, water disposal revenue was down $434,000 and our trucking revenue was down $384,000, water disposal was down 13% in revenue and trucking was down 20% revenue, but also as Kirk said, we had not only corresponding decreases in our expenses for those two main lines of business but additional percentages of decrease in our expenses, so for example, where our water revenue was down 13%, our disposal expense for that related revenue was down 33%. So was that 20% more than revenue was and we so the same thing on the trucking side, where trucking was down 20% in revenue, we had a 41% decrease in trucking expense. And as Kirk said some of that was due to fuel cost being less than they were last year, but it’s also a consolidated effort on behalf of management to decrease cost and then we saw additionally as he pointed already a 20% decrease from last year in SG&A. Now what all that means to us is that we think we have a structure in place to — that’s ready for the growth that we think we’re about to experience and don’t expect any significant increases in those cost, of course there’ll be some, but we think we are setup to experience good margins on there as we’re able to put these new wells and trucks in service and not only that but because of the fact that our wells are 100% joined to current offload facilities, the incremental expense related to those will be minimal and so we expect to benefit from the savings that we’ve experienced from our cost cutting activities and benefit greatly from that as we put these new assets on loan. You’ll also note that for in the press release that our net loss per share from continuing operations was $0.08 this year compared to $0.13 last year and so we’re looking forward to seeing that even cut further and moving toward profitability because these new assets come online in the coming months. Kirk? Kirk Trosclair Thanks, Ron. So, I think we want to talk a few more about the things that we have coming and then I’ll turn the call back over to Gary and then I think we’ll take some questions. But as far as the project is concerned down at Mills, we only have two wells left to turn on there. We have the one well in West Virginia that we are just awaiting the final approval to turn on at this point. So, those are some things we can look forward to happening in the remainder of 2015, the third and fourth quarter. We received the additional trucks that are scheduled to come in, the last few in October and we’ll see those hitting the roads as well. The other thing I wanted to touch on I guess would be, we’ll have some questions later. We are making some progress with the Coast Guard efforts on the barging situation. We have not started construction of any of the docks at this point but we have had several meetings with the Coast Guard, the meetings are going very well, nothing is set in stone at this point, they haven’t approved anything, most things are still in the same status as far as the regulations go but we have made significant progress with their team on coming up to a common solution to let this happen sometime in the near future. With that I’ll turn the call back over to Gary. Gary Evans I just want to emphasize a few things that were mentioned to which I think are really, really important. Many of us here have been in this business a long time, I’ve been in it for over 30 years and we’ve recognized a downturn was coming early on back in January and so, your management here began taking the efforts to reduce our cost. We knew that to be able to survive through a down turn you got to have lower cost. So, those are reflected in the numbers that we reported today and so as we continue to add volumes which we’re doing on a weekly basis that’s going to really drive our EBITDA and while we all look for better times in the energy industry we’re counting on year, year and half down turn. So, we’re not building the business with the anticipation that all of the great things that were happening in the prior three years are going to happen now. So, by being a leaner meaner machine we will become much more competitive with our existing competition in the region. We will continue to add capacity because we know its coming and then we got these joint ventures with a number of companies that are going to continue to add new volume. So, I’m actually quite excited about our future and I’m very excited that the wells that we put on at the Mills Hunter facility have taken so much water and so that in itself drives margin because we don’t have to put as many wells on because the volume take away capacity is much greater. We do believe we’re getting close as Kirk mentioned on the Coast Guard resolution. We continue to have a number of meetings with the Coast Guard, just to get dialogue and we believe we have some actions that we can take in the near future to begin barging and we’re keeping those close to our best for competitive reasons but when we do begin barging you will hear about it. So, with that let’s turn over the call to our listeners and operator and we’ll take our first question. Question-and-Answer Session Operator Thank you. [Operator Instructions] Your first question is come from [Dan Murphy] with Shareholders. Unidentified Analyst Good morning, gentlemen. Question on your preferred stock, noticed you didn’t pay dividend in July, there was nothing in the press release. Can you update us on the status of when you plan to pay or what’s going on with the preferred shares? Gary Evans Yes. The management board decided to because this is accumulative preferred to delay dividends at this time and so, we do not have an answer for you as to when we will begin paying dividends obviously something that we’re going to address but at this point in time the dividends will accumulate and we do not plan on paying in for at least a month or two. Operator Your next question comes from [indiscernible] Securities. Unidentified Analyst Yes, Gary, what concerned me more about the suspension of the dividend is that you didn’t see fits [indiscernible] signing the dividend. I mean, that’s [our pay], why didn’t you do that? Gary Evans Send the letter? Unidentified Analyst You didn’t send the letter; we’ve called the Investor Relations, nothing. Gary Evans Well, there is a real big reason for that. We were in negotiations with our lender; we did not know what the outcome of those negotiations were going to be and those negotiations did not conclude till about 30 minutes ago, so that’s the reason. I can’t tell you something that I don’t know about. Unidentified Analyst Yes, but, so in other words, your lenders are preventing you from making the dividend payments? Gary Evans That is correct. Unidentified Analyst Okay, now as follows the [code’s part of] concern, I’ve been following you, I’ve been a shareholder from several years now, and it’s like the same story with the [cold start], encouraging next month, next week, next year and it keeps going on and on, what is the problem? Gary Evans Hey, there’s a lot of problems with it, we’re dealing with a governmental agency, things take time and it’s not just a straight forward process. Unidentified Analyst But did they give you a reason why or they just say we’re not ready to talk about it? Gary Evans We have several reason why and we’re working with the Coast Guard to establish a policy that will be regulated by the Coast Guard and that we will adhere to. The basic answer to your question is that the reason we are not barging water today like we thought we’d be doing two years ago is bureaucratic backlog and we’ve had many meetings, we’ve had U.S. senators, U.S. congressmen involved, we’ve gone to Washington, we had many-many meetings and if you want to blame anybody, you blame this administration, they’ve tried to everything they could do to interfere in our business. So, we’re taking all measures possible to resolve the situation, we think we have a path that will resolve it. The Coast Guard I believe realizes there are issues here and for competitive reasons we don’t believe it’s an appropriate for us to disclose this or other companies would like to be doing what we’re hopefully going to be doing soon, but it is a bureaucratic mess and we have been trying to clean up the mess for two years and we have spent an ordinate amount of time in resources, in capital and trying to fix it so, if you want to pick up the phone and call the U.S. Coast Guard or call your Congressmen, I welcome it. Unidentified Analyst Now, that’s a possible thought and a final question is just short time ago, you were announcing that you had more business than you could handle, I mean you didn’t have enough capacity of salt water disposal to get all the water into the ground, has the drought been that severe in the past month? Gary Evans It is, it’s actually been that severe in the past two months, yes, a lot of our business is handling flow back water and when there’s a lack of drilling there’s a lack of water, now we do as I said believe we can fill these wells up and we’re in the process of doing that, we have many contracts and negotiations to fill these wells up, so we believe this is a short term operation but at the same time that we turned on our new wells, the same time the business dropped. Unidentified Analyst And the final question is, in the last conference call you stated that the actual flow down was actually a benefit to your company and I don’t remember exactly why but you said because the company’s behalf it was differently, they would be doing things with the water and like I said I don’t recall exactly why, but you said, we’d be actually be getting better margins, what happened to that? Gary Evans So, let’s talk about that, when drilling stops, the water that’s reused, in other words, it might go into pit, it might go in to tanks, it’s being reused for additional fracking, that can only sit there for so long and then that water has to eventually be disposed of and so, we’re beginning to see that right now, that’s just beginning to happen is that this water is stored down these areas the local state governments, the DEP, the EPA, they’re not going to allow the companies to let that water sit there, so, they have to go dispose of it, because they are not reusing it for refrack, so that’s what we’re referring to and companies have been sitting on that water a lot longer than we anticipated but we do see a whole swell of that business coming. Operator Your next question comes from Kevin [Rineheart] with [Derivates] Capital. Unidentified Analyst I’m wondering at what point is this company sustainably profitable? Gary Evans As we get these wells filled up, I mean these existing disposal wells filled up, I don’t think you saw the EBITDA reported this quarter but we reported good positive EBITDA so we’re getting there, if you look at cutting the cost that we’ve done and now if we get the water we need, we’re getting very close so, closer than we’ve been in a long-long time, is that right Kirk? Kirk Trosclair That’s absolutely right, we’re positioning ourselves for when the market does take a turn to the north to have really tremendous results, especially as it relates to EBITDA. Gary Evans I can see it’s been profitable next year just in relation to the 430 million Magnum Hunter drilling program in Ohio, I mean it’s going to keep GreenHunter extremely busy. Unidentified Analyst Another couple of questions, what is the current plan on retaining $13 million debt and the possible uses of the $3 million credit facilities still available. Gary Evans Well the $13 million debt has its own amortization schedule, so that’s how the plan is that’s outlined in the 10-Q. Additional $3 million is for predominantly the terminals that we need with respect to the barging. So, Kirk, Kirk Trosclair I mean that’s inside the $13 million that we’ve already taken in but the additional $3 million is for future projects that we have a six month window that we can go to the lender and if approved by them we can move forward with those projects. We have a list of probably $10 million to $12 million worth of projects that we have on a wish list. So we’re preparing that now, we’re prioritizing it and we’ll present that to them prior to the deadline and determine at that point if it makes sense as a management team to move forward and take the additional $3 million or to suspend that and move away from it. Operator Your next question comes from [Michael Huntsman] with [indiscernible] Unidentified Analyst Hi, Gary and Kirk. Just clarify a couple of items. There is a fair amount of production still happening in Utica, Marcellus, and it’s a pretty high water cut. So, is that the share you’re going after is to capture more produced water in the absence of the drilling activities through the first half and second half of this year, ex what Magnum Hunter is talking about doing? Gary Evans Michael this is Gary. We’ll take any order, reduced water, pull back order, whatever it is, we’re not that choosy right now but the one thing that’s kind of hurt our area is that with oil prices down that’s caused NGL and condensate prices to be down. So, Marcellus wells which were very, very active in our neck of the woods are not being drilled today and that’s because the cost of processing that condensated NGLs is today it’s a cost rather than it benefit, we used to get a $1.50 in McF uplift for McF on gas because of the rich liquids that associated with the Marcellus. Today, because of those low prices it cost money, a producer has to pay the cryogenic processing plant to process those liquids. So, that is really hurt the economics of Marcellus wells and so that’s been a huge drop in the drilling activity. On the flip side, the Utica wells, the dry Utica wells which is what Magnum just announced they’re going to be doing are very profitable, at $3 gas with no processing, with the takeaway capacities we have today, rates of return in the 40% to 50% range. So, you’re seeing a whole swell of switching from Marcellus and Utica and that’s all happening now and so you’re going to see this drilling activity pick up towards the latter part of the year with a number, there is new permits, Ontario which is one of our largest customers just permitted three new wells, two in [indiscernible] county, one in Dodgers county. So, we’re beginning to see that switch over occur and we think, that activity will definitely help us, because we have always been so full, it’s been so easy for us from the standpoint to get business as we have people waiting in line. Now we’re actually having to go out and get the business and we’re taking business from others and that’s what’s occurring, now we have two sales people, working full time in conjunction with Kirk and his team and he’s negotiating contracts every day. So, we see this as a very short-term aberration of we’ve turned on two significant wells that are doing much better we thought and guess what? The volumes weren’t there but they’re coming and you might just elaborate a little bit on that Kirk. Kirk Trosclair Yes, I don’t want to mention any specific names of the operators we’re working with Michael but we have new contracted take or pay capacity agreements out to three major E&P companies in that area, which total excess of 12,000 barrels per day, a take-or-pay capacity and one of those looks like it will probably be signed here by September 1 and the other one should be shortly after. The negotiations have been going on for a couple of weeks. It’s really tough to go out and sell something, when you don’t actually have the product in inventory. So, injection volumes was our inventory until we actually had the wells on, once we turned the wells on then we can actually hit the streets, people won’t talk to you until you actually have the volumes because it’s a one of those things where what do you have for me today. Gary Evans Yes, decisions are made today no, okay, well you have volumes on month well [indiscernible] now we got the volumes they just been turned on, we’re able to go get the new business Unidentified Analyst Okay. And I’m not trying to ask this, where I stand critical, but I’m catching the sense that the change in drilling happened so fast that, you were full for so long and not really worrying about sourcing, that when it changed so fast, your reaction time to fill it, the combination means that’s why we got this gap until — Kirk Trosclair It is somewhat of the gap Michael and one of the things that is probably to our determent at some points, but it’s also is going to a help us in the long-term, is all of that flow-back volume 75% or so of our fluids are traditionally production volumes. The 25%, or so has been flow backs and the majority of that flow back was coming from Triad. So we were saving space for Triad because of the agreements we have with them in place and then once those volumes dropped off, they dropped off the face of the earth, I mean really, really quick, we saw it coming, but yet we were still trying to chase some additional flow backs from different customers but that also dried up at the same time and then we turned on to new wells with increased capacity, so that’s why you see the utilization numbers down because of the increased capacity and we think that’s going to be short lived, we’re trying to grab additional production volumes right now, but we also have to be cognizant of the fact that this new JV program with Triad will be sending a tremendous amount of flow back volumes starting at the latter part of this year. Unidentified Analyst And then, one other things you’ve believed in the past Gary about the river of transport barging, was that — you could in fact do this despite the Coast Guard, what’s changed in that regard? Kirk Trosclair There’s a regulation out there, on the [indiscernible] 787, it’s an older regulation that was an addition to the existing rig and we had an avenue that we thought we could use and we still remain confident that we could have done that. Now would that have been the best thing to do, probably not, that’s why we kind off pulled back our horses, hey let’s all get at the same table and come to a common agreement. And we started working more diligently with the Coast Guard, being involved in meetings with those guys in DC and formulating a new angle to see this thing finally come to fruition. The rate itself that they proposed were going to see some changes to the rate that they had sent out in the latter part of 2013, and so we’re privy to some of that information , we’re not going to let it out at this point, we are doing some sampling this week for those guys of some [indiscernible] fluids and we’ll see what those results comeback and it really looks good and promising for us. I can’t tell you the timeline because obviously we don’t know that with the government, but this will happen eventually. Gary Evans I think maybe to summarize this, we had kind of gotten in because we were so frustrated into a bit of an adversarial position with the Coast Guard on this and started butting heads pretty bad and then we got some congressmen involved and things started changing so, we have a local congressmen in the West Virginia Ohio area that are having calls with the Coast Guard to try to understand why this has become such a logjam and a big issue and I think it’s a combination of some poor regulations that were written initially that were not understood and of course the Coast Guard had to sent this to the OMB, now OMB looks at it, they do their mental review and it goes back to the Coast Guard so, when I say that we’ve been tied up into a regulatory logjam, that’s a mild understatement and we have kept the pressure on and we have been using congressmen to do that and we’ve been having much more fruitful meetings off lately then we’ve had in the past. And that we think we’ve got the right people involved now, they understand the issues and it’s being addressed so, we do have some ways that we could begin barging pretty quickly that we’re working with the Coast Guard on, we’re not disclosing that for competitive reasons but we think all this talk about the Coast Guard can be put to bed for too long. Unidentified Analyst Can we talk about the price per barrel of disposal trends at the well-head and then transportation pricing as well? Kirk Trosclair Yes, sure, in the immediate onset of the downturn, everything was pretty steady and then going into the second quarter we started feeling quite a bit of a pricing pressure on transportation, that’s always the first thing that hits Michael, across the board out of any [all field] service company is on the transportation side. We’ve seen rates decline in transportation from probably $10 per hour, some places in excess of $15 per hour depending pretty much steady across the board from depending on which type of the truck it is, those have been the rate reductions that we’ve seen. Those are holding pretty steady, I think we’ve finally pretty close to the bottom on that, I don’t know if anyone can really go much further. Gary Evans There’s been some trucking companies going out of business. Kirk Trosclair The number of units out on the road have gone down, the disposal pressure really didn’t show it’s faith, so we actually opened our own wells and all this flow back material went by the wayside and we’re out their chasing production volumes, you have to make some modifications but what we’ve done to combat that is to go to the large E&P companies and even the smaller guard and offer longer term contracts for reduction in rate. So, with that being said, we’ve kind off offset those declines in pricing pressure with longer term contracts which are much beneficial to us. We’ve been offering some discounts from month or two to get them in the door and that’s worked up pretty well. Right now, with again no drilling going on of any significance. There is some pressure. We see that change, there is a dramatic shift going to this dry Utica can emphasize that enough and we think this is a very short list situation. Unidentified Analyst So, we still over $3 a barrel? Gary Evans Yes Kirk Trosclair [Indiscernible] number right here to be — but if you look in the — we were actually $3.39 a barrel for average compared to $3.14 last year. That’s probably peaked, but we raised rates just on the count spot rate to $3.75 last fall and we’re still benefiting from that. Unidentified Company Representative So, you got to see things remain pretty close to around $3 range Gary Evans We’re not talking dramatic, Michael. Unidentified Analyst Okay, alright. And then I suspect that the lender for the $13 million is — you are not paying any cash out so I make sure you’re paying me, do you have to get back to that $1 million of EBITDA, before on a LTM basis, before they would let you do this seriously? Gary Evans No, we have an amendment that’s been executed this morning that gives us flexibility and yours truly will probably be the one putting some more capital in to get back to paying the dividend. So, our goal is to get back to paying those dividends sometime before the end of the year. Unidentified Analyst Okay. And how quickly can you catch up on the accumulated part? Gary Evans We can do it tomorrow, if we wanted to. Unidentified Analyst Okay. Gary Evans There is no — we make sure that the amendment that we just executed gave us lots of flexibility and we have that. Operator Your next question comes from the line of Gene [indiscernible]. Unidentified Analyst Just a couple of questions, I think we haven’t talked about for a while. First is the MLP, is that just the financing that you’ve gotten from your senior lender take that out of the question and what is the status with the IRS? Gary Evans Good question. We definitely believe this business is conducive for an MLP, you’re seeing more and more midstream companies put water business in their portfolios, so I’d midstream, gas gathering processing company and so we are still waiting for our revenue [indiscernible] letter, we’ve had our law firm working with IRS on that, we do believe that is a much cheaper form of financing for us in the future and that will likely not happen in 2015, it will be a 2016 event. Unidentified Analyst Okay. And is there any read through, obviously, you haven’t closed anything but you have — you make it in discussions, Magnum Hunter for the sales 45% [Eureka Hunter], is there any read through that you can get from there, in terms of what the MLP appetite is for these kind of assets, I mean, obviously it’s not exactly like [Eureka Hunter] but it’s not so Gary Evans The appetite for anything in this part of the country is exceptional, we’ll be announcing the eventual winner of the [Eureka Hunter] here over the next week to 10 days hopefully. It’s been a frothy exercise with tremendous amount of interest and we’ve had companies trying to circumvent the process whatever they could do to get the assets, so, we’re obviously trying to get the most value we can and we don’t see anything different with respect to the water business going forward. So, this part of the country is where every midstream guys wants to be because it has the highest growth potential because of the raw characteristics of the region. Unidentified Analyst And I guess along this lines another, I think that you talked about before was the pipeline, you have been working with nature pipeline obviously they couldn’t get the financing, is that still an option for the future and is that the sort of — were you far enough down the road there where you have rights of ways and things like that or is that more just an idea? Gary Evans We did buy any rights to way but we continue to talk to producers about consolidating their trucking operations in certain areas. So, that is still something that we are looking at and pursuing, it’s just the slowdown in activities caused everybody to kind of pull in their reigns a little bit and look at their base of business. So for us, our main focus is to get these wells filled and then we will be looking at these other opportunities. Operator And there are no further audio questions at this time. Gary Evans Thank you operator and thank all of you for listening in. It’s been a bumpy quarter but we did get lot accomplished and we look forward to reporting our ability to fill up our disposal wells going forward and other activities we have going on again. I think the new JV that Magnum is doing with these private equity partners are going to have a huge benefit for GreenHunter in late 2015, early ’16 actually goes for two years or 24 months, so we’re going to continue to keep our costs down, continue to cut them where we can, as Kirk mentioned these new 407 trucks are coming in, we’ll have them fully utilized as they hit the streets because of the type of vehicle they are and we’ll continue to look at adding additional capacities, so you think we’ll, gosh you haven’t filled up your existing wells, why are you looking for new capacity. We know what’s coming and we know we have to have additional capacity, so we’re working hard to do that. So, with that, feel free to call if you have any specific questions to our investor relations area and we’ll get back with you. And thank you for your time today. Operator Ladies and gentlemen, this does concludes today’s conference call and you may now disconnect.

Eversource Energy’s (ES) Q2 2015 Results – Earnings Call Transcript

Eversource Energy (NYSE: ES ) Q2 2015 Earnings Conference Call July 31, 2015 09:00 ET Executives Jeff Kotkin – Vice President, Investor Relations Jim Judge – Executive Vice President and Chief Financial Officer Lee Olivier – Executive Vice President, Enterprise Energy Strategy & Business Development Jim Muntz – President, Transmission Phil Lembo – Vice President and Treasurer Jay Buth – Vice President and Controller John Moreira – Vice President, Financial Planning and Analysis Analysts Dan Eggers – Credit Suisse Julien Dumoulin-Smith – UBS Steven Berg – Morgan Stanley Travis Miller – Morningstar Shar Pourreza – Guggenheim Michael Lapides – Goldman Sachs Andrew Weisel – Macquarie Caroline Bone – Deutsche Bank Operator Welcome to the Eversource Energy Second Quarter Earnings Call. My name is Christina and I will be the operator for today’s call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Jeff Kotkin. You may begin. Jeff Kotkin Thank you, Christina. Good morning and thank you for joining us. I am Jeff Kotkin, Eversource Energy’s Vice President of Investor Relations. Some of the statements made during this investor call maybe forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management’s current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release issued yesterday. Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2014 and our quarterly report on Form 10-Q for the three months ended March 31, 2015. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night on our website under Presentations and Webcasts and in our most recent 10-K and 10-Q. Speaking today will be Jim Judge, our Executive Vice President and CFO and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy & Business Development. Also joining us today are Jim Muntz, President of our Transmission business; Phil Lembo, our Vice President and Treasurer; Jay Buth, our Vice President and Controller; and John Moreira, our Vice President of Financial Planning and Analysis. Now, I will turn over the call to Jim. Jim Judge Thank you, Jeff and thank you all for joining us this morning. Today, I will cover a strong second quarter financial results, which were in line with our guidance range for the full year. Our strong operating performance and update on several legislative and regulatory items and I will close with an update on certain transmission projects. Let’s start with Slide 4 and our financial results. Excluding merger-related costs, we earned $209.6 million, or $0.66 per share in the second quarter of 2015 compared with earnings of $131.9 million, or $0.42 per share in the second quarter of 2014. Over the first six months of 2015, we earned $466.9 million, or $1.47 per share, excluding those charges compared with earnings of $373.7 million, or $1.18 per share in the first half of 2014. These results strongly support our full year earnings projection of $2.75 to $2.90 per share as well as our targeted long-term annual earnings growth rate of 6% to 8%. Turning to Slide 5, a significant driver in the second quarter year-over-year earnings growth was the absence of a $0.10 charge we recorded in the second quarter of 2014, resulting from the initial decision from FERC on the allowed transmission ROEs for New England transmission owners. There was no similar charge this quarter plus we continue to realize the benefits of our continued investment in New England transmission reliability enhancements, which added $0.01 to earnings. As a result, our transmission earnings totaled $0.25 per share in the second quarter of 2015 compared with $0.14 per share in the second quarter of 2014. On the electric distribution side, higher retail revenues primarily due to last December’s Connecticut Light & Power distribution rate decision and a follow-on order from earlier this month involving accumulated deferred income taxes added $0.10 per share to earnings. I will discuss the July decision more fully in a moment. We continue to evidence good cost discipline as we have lower O&M – lower non-tracked O&M expense this quarter that reflects a decline in labor and labor-related costs and added $0.06 to earnings. I should point out that part of the large O&M decline this quarter, in fact, $22 million of the $56 million you will see in the income statement are costs that we don’t have any more as we sold our electrical contracting company early in the quarter. So, $70 million of annualized O&M will go away. There is really no real earnings per share impact as obviously the revenues will go away as well. Back to the reconciliation for the quarter. As expected, earnings were negatively affected by $0.06 due to higher property taxes, depreciation and amortization expense associated with storm cost recovery. Other factors impacting the quarter which include improved generation earnings and lower income taxes added another $0.03 per share. In terms of operations, our electric and natural gas delivery systems have performed well over the first half of the year. Our electric restoration metric, which represents the average number of months between interruptions, continues to track favorably as our reliability metrics are now consistently in the top quartile of our industry. Turning to our state legislatures, we had an active and successful spring. In Connecticut, Governor Malloy signed Public Act 15-107, which among other initiatives will allow electric distribution companies to sign long-term supply contracts with interstate natural gas pipelines. We will discuss the significance of that act shortly. Turning to Slide 6, in New Hampshire, the Senate and House overwhelmingly endorsed modifications to the state’s securitization statutes which are key to public service of the New Hampshire’s divestiture of its generating assets and recovery of those costs. The divestiture process has now moved to the New Hampshire Public Utilities Commission, where we filed a comprehensive restructuring and rate stabilization settlement agreement on June 10. That agreement was signed by a wide range of parties, including the Governor’s Office of Energy and Planning, two key state senators, senior New Hampshire PUC staff, the Office of Consumer Advocate, the IBEW local representing PSNH’s unionized workers and the Conservation Law Foundation among others. In addition to divestiture of PSNH’s 1,200 megawatts of generation, other terms of the agreement called for PSNH to defer a distribution rate case until at least mid 2017, the continuation of PSNH’s reliability enhancement program and the related cost tracker, foregoing $25 million of deferred equity return on the scrubber, and funding by Eversource shareholders of $5 million of clean energy initiatives. Parties to the settlement agreement have asked the New Hampshire PUC to rule on the agreement by December 31, 2015, which should allow the planned sale process to occur in 2016. As part of the agreement, the Commission’s review of Merrimack Station’s scrubber investment will end. We firmly believe that the agreement we filed will benefit all New Hampshire’s stakeholders over the long-term, which is why it is so widely supported. Turning from New Hampshire to Connecticut in Slide #7, on July 2, PURA approved a settlement we have reached with the authorities prosecutorial unit concerning the treatment of accumulated deferred income taxes in setting rate base in last December’s general rate case decision. The settlement restored approximately $165 million of distribution rate base and will add about $18 million of distribution revenues annually that’s retroactive to December 1, 2014. We recorded $11 million in the second quarter for the period of December 1, 2014 to June 30, 2015. In Massachusetts, we received two positive orders from state regulators relative to our plans to step up investment in our natural gas delivery system. The GPU approved a mechanism to recover investments related to the significant upgrade of our 3 billion cubic foot liquefied natural gas storage facility in Hopkinton, Massachusetts over the next several years. We expect to invest up to $200 million in that 40-year full facility, which is critical to helping NSTAR gas meet its winter supply obligations. Additionally, the DPU approved the first step in NSTAR Gas’ accelerated replacement of its cast iron and its untreated steel pipe over the next 20 years or 25 years. Those expenditures which were expected to rise to more than $60 million a year by the end of this decade will also be recovered through a distribution rate tracking mechanism. Later this year, we also expect to file a natural gas expansion plan to NSTAR Gas to comply with the state legislation that was approved last year. NSTAR Gas is our only distribution company where we have a rate case pending, hearings in that case were a base distribution rate increase request is approximately $23 million. Hearings were held in June and the decision is expected in the fourth quarter. New rates will take effect January 1, 2016. I would like to touch on energy rates for a moment. On July 1, the default energy rates at all four of our electric distribution companies dropped significantly from as high as $0.15 per kilowatt hour to between $0.0825 and $0.10 a kilowatt hour. This reduction, which is a pass-through for us mostly impacts our residential customers, the vast majority of whom have not moved to a third-party supplier and continue to buy their energy from us. While our customers will benefit from this decline through December, rates are very likely to rise again significantly in January when New England’s acute shortage of natural gas pipeline capacity will again pressure electricity prices. This see-sawing of energy rates is not healthy for our region’s economy and Lee will discuss in a moment the long-term initiatives that we have underway to resolve this dilemma. In Washington, hearings at FERC concluded this month on the second and third complaints filed regarding the return on equity earned by New England transmission owners. Earlier this year, FERC reaffirmed a base ROE of 10.57%, down from its previously allowed 11.14%. We believe that the 10.57% base is a reasonable level and booked reserves in the second quarter of last year and first quarter of this year, to reflect FERC’s final order. We are due to receive a FERC ALJ initial decision late this year and expect the commission order in the third quarter of 2016. Turning from regulatory issues to financing, we are pleased with the outcome of our annual rating agency reviews. On our first quarter earnings call I mentioned that the S&P had raised its corporate rating on Eversource and its subsidiaries from A- to A with a stable outlook. S&P also upgraded Eversource’s commercial paper rating to A1. Subsequent to that upgrade, Fitch raised the outlook for CL&P, PSNH and WMECO to positive and Moody’s raised its outlook for PSNH and WMECO to positive. We believe these actions speak loudly about how well we are operating the business and how many important regulatory items have been successfully resolved. Now turning to Slide 8, I will provide a brief update on some significant transmission projects. Our share of the Interstate Reliability Project which we are building in Northeastern Connecticut has finished major construction and the project was about 97% complete as of June 30. Right of way restoration remains and we expect the entire project in Connecticut, Rhode Island and Massachusetts to be in service later this year. We have now made three filings with the Connecticut Siting Council for projects included in the $350 million Greater Hartford seven [ph] solutions and all have now been improved with one already under construction. We continue to estimate that all Greater Hartford projects will be completed by the end of 2018. On this slide, we also highlight some additional transmission projects in New Hampshire that have been in our forecast and guidance. On July 21, we and National Grid filed a joint application within New Hampshire Site Evaluation Committee to build the Merrimack Valley Reliability project. Our share of the project would cost approximately $37 million. Separately we are going through the pre-filing process of the Seacoast Reliability Project, which is part of the New Hampshire 10-year reliability initiative we have been discussing with you for a few years. We are reviewing our $70 million cost estimate for the Seacoast project as we incorporate input from the towns that will host the project. These projects underscore the continued economic growth we see in New Hampshire and Eastern Massachusetts. Altogether, our capital expenditures totaled $771 million in the first six months of the year, $324 million of which was spent on our electric transmission system. We continue to project total CapEx of $1.85 billion this year to $740 million of which will be invested in transmission. That concludes my formal remarks. Now I will turn the call over to Lee. Lee Olivier Thanks Jim. I will provide you with a brief update on our major capital initiatives and then turn the call back to Jeff for Q&A. Let’s start with Northern Pass profiled on Slide 10. U.S. Department of Energy released its draft environmental impact statement on July 21. We have begun our review of the document and do not believe it poses any unanticipated challenges to the construction of the project. We were pleased that the draft EIS included that there would be a very low to low visual impact on our Northern sections of our preferred group. As expected, the DOE reviewed a number of alternative routes of the project in addition to our preferred configuration. We will carefully evaluate these alternatives. The considerable breadth of these alternatives should ensure that the project configuration ultimately approved by New Hampshire regulators will have been analyzed by the DOE. While the draft EIS is now released the DOE has scheduled hearings on the report for early October and asked for written comments by the end of October. Now that the DOE has issued its draft review, we expect to file with New Hampshire Site Evaluation Committee for our state siting approval in the early to mid-fall. The new state process requires a series of public meetings on the project at least 30 days before the application. So you should expect those meetings to be scheduled soon. Once we file our application to site evaluation committee, we will have up to two months to determine that the submittal is complete and then up to 12 months to rule on it. Our state application will incorporate feedback from the DOE’s draft EIS, as well as from the ongoing outreach in New Hampshire to ensure it is viewed favorably by a wide range of stakeholders. As part of our engagement with New Hampshire stakeholders, we announced on June 16, a new and unique partnership that will create significant opportunities for New Hampshire workers and businesses to participate in our upcoming transmission projects in the state. This would include Northern Pass and about that $800 million we expect to invest in other New Hampshire projects over the next 5 years some of which Jim has referenced earlier. The Jobs program focuses on three key areas of employment. They include a commitment to hire New Hampshire workers first, their commitment to New Hampshire-based construction related companies, many of them family-run to have an opportunity to bid on our projects a first of a kind training program to allow New Hampshire apprentices to be paid while training for high demand work on electric transmission construction. This effort has been coordinated with IBEW and our major electrical contractors. We look forward to the many of these New Hampshire residents and companies working in Northern Pass. The project continues to offer enormous benefits to the State of New Hampshire and to the region as a whole. We continue to estimate the cost of approximately $1.4 billion for Northern Pass, but that could change depending on the conditions related to the regulatory approvals. Turning to Slide 11, you can see that we expect to receive both state and federal siting approvals of the project in late 2016, commence construction around the end of 2016 and have the project substantially complete on both sides of the border by the end of 2018, with testing and entering into full commercial operation in the first half 2019. This schedule is similar to what I discussed with you in May. Turning to Slide 12, New England continues to make progress towards addressing significant energy challenges facing the region. One of these challenges is the need for new clean sources of power especially as we witnessed the ongoing retirement of older coal, oil and nuclear units. Northern Pass will provide some of that clean power, but other additional sources would be needed to meet the renewable energy and carbon reduction mandates New England and other states have enacted into law. In late February, the state of Massachusetts, Connecticut and Rhode Island jointly unveiled a draft solicitation for clean energy sources that will require new electric transmission to be built. The draft RFP asked for proposals for power purchase agreements as well as for the construction and transmission that would tap into clean energy. In late June, the final proposed RFPs were submitted to Massachusetts and Rhode Island through regulators for approvals. Connecticut legislation does not require that step. We expect that regulatory sign-ups on their RFP will occur over the next couple of months and the RFPs will be released to potential bidders shortly thereafter with bids due late this year. In Massachusetts, Governor Baker filed legislation on July 9 that calls on the state to purchase up to 18.9 million megawatt hours annually of clean hydroelectric power and other renewable energy. That equates to about 2,400 megawatts of capacity. We expect the legislature to take up the Governor’s bill this fall. But earlier this week, Governor Baker’s Energy Secretary, Matthew Beaton, said that the Governor has made the bill one of his priorities since without hydropower, the state will fall short of emissions reductions targeted by the state’s landmark 2008 Global Warming Solutions Act. In addition to taking steps to address its clean energy goals, New England has also made significant progress towards improving the availability of natural gas to fuel power generation during the winter. As I discussed on our first quarter conference call, New England and federal policymakers are very concerned about the shortage of natural gas capacity into the region during cold weather months, New England is challenged by a lack of gas pipeline capacity into a region, a shortage of natural gas storage and a heavy and growing dependence on natural gas generation. These constraints caused New England to suffer the three highest price months ever in New England for wholesale electricity prices in January and February of 2014 and February of this year. Further, natural gas prices in New England this past winter were almost doubled the national average even though we are located so close to the Marcellus gas fields. Without action the fuel constraints that we are seeing are driving skyrocketing prices will only continue and intensify. ISO New England recently stated that it expects 10% of the region’s generation fleet to retire by 2018 and possibly another 5,000 megawatts by 2020. These units will be oil and coal fire. More natural gas generation will take your place pressuring gas supplies and customer rates even further. The region’s policymakers recognized the severity of this challenge and are taking action. Turning to Slide 13, let’s start with Connecticut legislation as Jim mentioned earlier, on June 22, Governor Malloy signed Public Act 15-107. This bill provides clear authority for state regulators to allow electric distribution companies to sign long-term supply agreements with interstate natural gas pipelines. We expect the Department of Energy and Environmental Protection to solicit proposals later this year. In Massachusetts, Department of Public Utilities opened the docket in April to examine whether we could – whether it should consider allowing electric distribution companies to contract for interstate pipeline capacity. We, along with National Grid and the government’s Department of Energy Resources, strongly believe the DPU’s authority to approve such contracts is clear under state law. Initial comments were filed in June and reply comments in early July. Although the DPU has not set a timeline for the remainder of the investigation, we anticipate the DPU will issue its findings later this summer or early fall. In New Hampshire, the Public Utilities Commission opened its own docket in April to investigate the means by which electric distribution companies could ameliorate adverse wholesale electric market conditions caused by natural gas constraints. Stakeholders filed comments in June. Further, the PUC staff released its preliminary conclusions earlier this month that electric distribution companies have the necessary authority to contract the natural gas capacity. The PUC staff will provide a report to the Commission by September 15 of this year. In Maine, the Public Utilities Commission conducted an RFP late last year as part of its mandate to bring up to 200 million cubic feet a day of incremental natural gas capacity into the state. Access Northeast bid into that RFP and in May Central Maine Power filed with the Maine PUC recommending that it be allowed to contract with Access Northeast to bring in additional gas capacity. The consultant hired by the PUC analyzed the proposals, issued its report earlier this month including that Maine going it alone would not be justified. We believe this reinforces the need for a multi-state effort. All of these actions point to the increased recognition by policymakers that New England requires additional interstate pipeline capacity to ensure electric grid reliability and stable pricing. As we have said previously, we believe that the $3 billion Access Northeast project we are developing with Spectra Energy and National Grid is ideally suited to address New England’s natural gas infrastructure challenges since it would include upgrading Spectra’s existing pipelines in New England. Our project is unique, uniquely situated to deliver increased quantities of natural gas to the region’s newest and cleanest generators to inspect those pipelines and our alliance with Iroquois Pipeline connect us to directly to more than 70% of the region’s gas fire units. To remind you, Spectra and Eversource would each own 40% of the project and National Grid would own 20% of the project. The project’s open season ended May 1 and it received a strong response from both electric and natural gas distribution companies. The Access Northeast has commenced the process of negotiating long-term contracts with those distribution companies. We expect that pipeline customers will file those contracts with state regulators later this year with the goal of securing state regulatory approvals in 2016. With respect to sitting and citing and permitting, we plan to commence our FERC pre-filing later this year. This will facilitate a formal certificate filing at FERC in 2016. We expect to bring the pipeline into service for the winter of 2018/19 assuming expeditious approvals by federal and state authorities, because of the longer construction timeline for LNG facilities, we anticipate the storage element of the project will commence service after the pipeline. On July 27, we announced LNG, the LNG element of Access Northeast of public meeting in Acushnet, Massachusetts. That element involves the construction of 6.8 Bcf of LNG storage in Acushnet where Eversource currently operates an LNG facility. This LNG facility has been operated safely and reliably for nearly 45 years. The combination of the enhanced Spectra pipeline system and the additional domestic natural gas will allow us to ensure up to 5,000 megawatts of natural gas generation will remain online even during the coldest winter months. Now, I would like to turn the call back over to Jeff for Q&A. Jeff Kotkin Thank you, Lee. And I will turn the call back to Christina just to remind you how to enter questions. Christina? Question-and-Answer Session Operator Thank you. We will now begin the question-and-answer session. [Operator Instructions] I will now turn the call back to Jeff. Jeff Kotkin Thanks, Christina. Our first question this morning is from Dan Eggers from Credit Suisse. Good morning, Dan. Dan Eggers Hey, good morning. Just on the process right now, I guess for Access Northeast, you guys will pre-file this year. FERC will give you a response what time in 2016 and then when would you expect an official formal approval and then start actually spending money on construction under the timeline you laid out today? Lee Olivier In regards to the pre-filing, we will do the pre-filing approximately in the fourth quarter of this year. And then we will do the certificate filing somewhere between the third quarter and fourth quarter of next year. And clearly, at the beginning of this project the capital expenditures, our investments are very low. And what we are doing now was we are putting together the capital flows and cash flows for next year. And we will have a better sense of those later in the year most likely at our conference in the fall in November at EI conference. Dan Eggers So, we will look for the capital update, but probably no real dollars going to work until what, ‘17/18, is that realistic? Lee Olivier I think that’s a reasonable conclusion. Dan Eggers And from confidence, obviously the open season is showing interest, do you guys need to see more state approvals in some of these process you have pending before everybody is going to be onboard for signing firm agreements at this point? Lee Olivier Well, in the case of Connecticut, they don’t need commission approval. What’s happening there is the Department of Energy Environmental Protection are putting together a RFP process. They are in the midst of doing that. They will go out with an RFP. Massachusetts, we expect by late this summer, early fall, will have signed off on the RFP and it will be issued then. And essentially, once the RFP is issued, this is on electrics, once the RFP is issued, there is about 75 days that will be required to get your bid in. So we could expect bids in the fall and to choose the winners, of late this year, early next year. And on gas, it really is going to be, it’s a little bit different. The only state that wants to using RFP process is Connecticut. The other states right now have not really made the determination whether they want to follow that or just used the standard kind of LDC process where we will file the EDCs will file the President agreements with the regulatory bodies and that will kick off an approval process that could take anywhere from three months to six months. Dan Eggers So we shouldn’t see the bulk of these contracts somewhere around year end I guess then the gas utilities could be a little bit later but within the next six months to nine months we will know how firm and who is presumably going to take the capacity? Lee Olivier Yes. I think that’s a good estimate of the time six months to nine months is a good estimate. Dan Eggers Okay, very good. Thank you, guys. Jeff Kotkin Thanks Dan. Next question is from Julien Dumoulin-Smith from UBS. Good morning Julien. Julien Dumoulin-Smith Good morning. So the first quick follow-up on the last question there if you can. In regards to the procurement, as you are thinking about what’s contemplated obviously to early days for Connecticut and Massachusetts, will this ultimately be sufficient to get your projects off the ground, what’s the quantity contemplated at least as you are seeing the frameworks proposed between just the two states today to get your project and plus other projects off the ground, what’s the total volume, if you will? Lee Olivier Julien, this is Lee. You are referring to the gas side? Julien Dumoulin-Smith Yes indeed. Lee Olivier Yes. In the gas side, we expect to get something very, very close to the 900,000 decatherms per day. Julien Dumoulin-Smith Okay, great. And then second question, somewhat related going towards to the other side of the house on the transmission, as you look at the Massachusetts legislation, how do you think about that tying into the present RFP that you just discussed, would that ultimately be an upsizing or how would that ultimately get feathered together? Lee Olivier And this is in regards to the three state electric RFP and Governor Baker’s proposed legislation. Julien Dumoulin-Smith Exactly, how do you see those two working together? Lee Olivier Currently, without that legislation the Massachusetts really would be interested in this deliverability commitment model whereby you buy essentially – you pay for transmission and you get a supplier on the other end that will deliver electricity on an agreed upon, essentially capacity factor or numbers of megawatt hours over the course of the year. So that would be their option there. If the Governor Baker’s legislation passes, then you really have the full range inside of the free state RFP. You would have the deliverability model. You can do transmission with PPAs or they could do PPAs as well. So just in the full range of what the options are in the current RFP. Julien Dumoulin-Smith Great. Thank you. Jeff Kotkin Thank you, Julien. Our next question is from Steven Berg from Morgan Stanley. Good morning Steven. Steven Berg Good morning. Thanks for your time. I wanted to follow-up on Dan’s question just on the approval process and Lee you laid out sort of a 6 month to 9 month timeframe. On the gas side, could you give us some indication in terms of just key regulatory items we should be trying to follow throughout the course of the fall and through the winter time just so that we can better understand sort of the sequence or the key things we should be looking for there? Lee Olivier Yes. Clearly, a key thing is the RFP process in Connecticut that will be run by R&D, which we expect to take place this fall. It will be the signing of the precedent agreements by the EDCs and LDCs, because it’s both and the filing of those precedent agreements that will take place essentially late third quarter, early fourth quarter, it will be the approval by the Massachusetts DPU of the RFP process. So, those are the kinds of things that you can expect to see, not the approval of the RFP process, but the approval of the docket that allows the EDCs to purchase gas infrastructure. So, those are some, again I said the pre-filing will be late this year and you will hear – we will continue to do the further rollout of our Acushnet facility, our LNG facility in Acushnet and you will hear more about that. Steven Berg Okay, that’s very helpful. And just shifting gears over to just follow-up on what you have mentioned in Massachusetts with the Governor’s legislation proposal. It’s great that it sounds like it’s a key priority for the Governor. Could you just speak to for the proposal broadly, any your sense for, are there key elements of or sort of features that have drawn our position or is this something that is generally that you think broadly you have supported politically, how do you kind of think about the politics of it? Lee Olivier Well, look, Jim you may want to catch up that one a little bit. Jim Judge I mean, Steven, this is Jim. I would characterize it as similar to what we saw in Connecticut. Governor Malloy’s Connecticut energy strategy recognized that there are low-cost clean sources available in terms of Canadian Hydro that can help the state achieve its carbon reduction goals. I think the same mentality exists in Massachusetts among the policymakers. So, obviously its draft legislation at this stage would need to be approved on Beacon Hill and then signed by the Governor, but we think there is recognition that clean resources are available and within reach and we need to sort of be on with it in terms of enabling the commitments to be made. Steven Berg Great, thank you very much. Jeff Kotkin Thanks, Steven. Next question is from Travis Miller from Morningstar. Good morning, Travis. Travis Miller Good morning. Thank you. On the O&M cost side, if you take out that business that you guys divested there, how are you thinking in terms of tracking your O&M savings targets for the year, behind ahead, on track, so far this year? Jim Judge Yes, the guidance that we gave, Travis, for the year was O&M reductions of 2% to 3%. And when we adjust out the sale of that electric contracting business, I would say we are probably closer to 4% year-to-date. So, we are out little ahead of it. I would caveat that by saying that we do know that there is some timing in those numbers that we have gas and electrical maintenance plans that are lagging behind slightly. So, we will probably catch up on some of that. So, while we are ahead of plan year-to-date, I think the guidance continues to be 2% to 3% for the year that we are comfortable in giving. And that nets out obviously excluded the business that we have sold here in the second quarter. Travis Miller Okay. And then what was the full earnings impact, the bottom line impact from that business, if you include that revenue? Jim Judge It was relatively small fractions of $0.01. We have $2 million a year that order of magnitude. Travis Miller Okay, great. Thanks so much. Jeff Kotkin Thanks, Travis. Next question is from Shar Pourreza from Guggenheim. Good morning, Shar. Shar Pourreza Good morning. Just one question on Northern Pass, the Jobs program that was announced as well as the property tax payments reductions, can we just get a little bit of a sense on what formed the basis of those terms with this from feedback you received from constituents within the state and sort of – is this sort of the foundation for settlements? Lee Olivier Yes, Shar, this is Lee Olivier. We are not looking at this as a foundation for settlement, because we really believe that the process that’s in place now in New Hampshire is best lift through kind of a litigated process. We think ultimately out the other end it will have more integrity if it’s through the litigated process. Clearly, New Hampshire wants to understand, being the host, they want to understand the values of that line to New Hampshire from the standpoint and what does it do to lower electric cost to the extent that they can have a power purchase agreement, to the extent that it creates jobs both during the construction in permanent jobs, to the extent that there is other financial value to the state. And so this is after a lot of conversations with elected leaders, municipal officials and other key stakeholders in the region, including obviously, labor, the environment. And so what we will have when we announced the project will be a comprehensive value proposition that we will present to New Hampshire that will provide significant benefit in terms of jobs, revenues, tax revenues and other support for the state over a long period of time. So, we believe, coupled with the draft, EIS, coupled with our own outreach around the existing route and changes that we could make reasonably that the combination of all of those will have wide acceptance in the state when we file our application at the SEC in the early fall timeframe. Shar Pourreza Okay, got it. So, just one clarification, so the Jobs program and the property tax payments that was from conversations you have had with constituents within New Hampshire? Lee Olivier Yes. Well, the property tax payments will just be the standard mill rate on any given area. In other words, how much infrastructure is in a town, what’s the particular towns’ mill rate, what’s that infrastructure worth, what do we have on the books and they will be paid accordingly, very standard is how we do all of our other transmission. And then the other services provide will have been, if you will, discussed with the key stakeholders and we will reach a joint decision on those. Shar Pourreza Okay, perfect. And then just on Access Northeast, once you get the firm contracts, sometime I guess next year, is there a point where we can get closer as far as upsizing the pipe through laterals and compressors? And then just lastly on the storage project, is there any kind of a quantification of what that spending outlook could be? Lee Olivier On the latter one, the storage, that’s approximately $800 million of investment out of the $3 billion of the project investments, that’s about $800 million. And those are, our first cut up the number is that’s doing some engineering, heavy engineering consulting and understanding where the market is right now will mind for LNG. So, we think right now $800 million is a good number for 6.8 Bcf. And if you look at the project, the LNG would provide about 400,000 decatherms a day. The pipelines would provide around 500,000 decatherms. So, our project right now is approximately 1 Bcf and that’s the project that we will proceed with at this time. Shar Pourreza Great, thank you so much. Lee Olivier You are welcome. Jeff Kotkin Thanks, sir. Next question is from Michael Lapides from Goldman Sachs. Good morning, Mike. Michael Lapides Good morning, guys. Congrats on a good quarter. Two separate questions. The first one, you have two big projects, I mean, two really big projects, Northern Pass and Access Northeast. There are other market participants who are proposing new transmission down into New England, some of which with more underground routing than overhead. There is also one or two other parties, or consortium trying to get new major pipeline built. Can you talk for each of those two projects, the competitive positioning, the difference between your project recommendations and some of the others that are out there in the market? Lee Olivier Yes, sure. Michael, this is Lee. I think looking at Northern Pass, clearly, the entity or utility that has the most hydropower available in North America is Hydro-Québec. And they are the closest geographically to New England, have tie lines into New England currently. And they are partners and they are only working on one interconnection between Québec and New England and that’s ours. Okay. So, they are not working on any other interconnection into New England. So, they are our partner here in New England. So where that would lead you is to if you look at other hydro sources, they would be in the [indiscernible] region, those are small in nature. They are under development, could show up in the next 15 years from now, but they don’t provide any meaningful supply into New England during that period of time. So, from that standpoint, our project, you know what 1,200 megawatts and you look at big part of what’s driving Governor Baker and others, it’s all about carbon reduction. If you want to get a picture, 50%, 80% carbon reduction by 2015, you need a lot of energy that doesn’t produce carbon that runs around the clock. And clearly, that transmission project is the best one to go do that. There will be other projects that will be wind projects. Some of them may have run-of-the-river, firmed up by their wind with run-of-the-river firm and the wind up, but those are smaller projects in nature, the 400 to 500 megawatts. And then you are probably looking at some big wind projects, we will say farther up in places like Maine. You have all the issues of building large transmission infrastructure to correct relatively speaking small amounts of energy. When you look at the wind capacity factor of 35%, the intermittency of that probably doesn’t have the huge carbon impact when you consider what you are paying for. So, that’s kind what the competition looks like there. On the gas side, it’s real clear. We are building a project that interconnects with 70% of the region’s generators. It is using existing right of ways, existing LNG facilities. It will pick up both EDCs, LDCs. It has future potential expansion capability. The competition is building a pipeline that is designed around serving LDCs and is in an area where it’s very difficult to interact with a whole lot of that 70% of the generation I just talked about. So, we think from that standpoint, we think that project is very well-positioned. And we had a very successfully rollout of our LNG in Acushnet, Massachusetts earlier this week. Michael Lapides Got it. One follow-up easier question, when you are thinking about whether there is a new normal for gas utility, demand growth, especially at the residential and small commercial. How do you think about that and how different is that across your systems? Jim Judge Well, this is Jim. Long-term gas growth rate that we are assuming in our 5-year plan and the guidance that we have provided is 4%. Now, you may not get those growth numbers in other regions of the country, where gas penetration is more significant. We have a huge opportunity in Connecticut, as well as in Massachusetts in terms of converting customers to gas heat at their homes. In fact, we have got attractive mechanisms in Connecticut in terms of cost recovery for that. So, we are targeting about 11,000 conversions this year. In spite of the decline in oil prices, we are actually ahead of plan. I think we have signed up 4,800 in the first half of the year. So, we have got 2% plus growth just on new customers. And then obviously, the volume is likely to grow as well. So, we feel pretty confident about our 4% growth rate long-term. Again, I don’t know that I would apply that to other utilities or other regions of the country. Michael Lapides Got it. Thanks guys. Much appreciate it. Jeff Kotkin Thanks, Michael. Our next question is from Andrew Weisel from Macquarie. Good morning Andrew. Andrew Weisel Good morning. Two questions on Northern Pass. Jeff Kotkin Andrew could you just speak up a little bit? Andrew Weisel Sure. Sorry, two questions on Northern Pass, first with the RFPs that you described, given that this is an economic base project, do those really matter if the project succeeds in bidding those RFPs and if so would that affect your economics, Hydro- Québec’s or the rate payers? Lee Olivier I think – this is Lee, Andrew. I think the way we would answer that is there is this existing RFP process that’s been made available to all entrants. So obviously, we in HQ would enter this project into – to that process because to go forward independent of that would provide the others that would bid in and we are chosen to have the competitive advantage over Northern Pass. So I think it’s appropriate that this project, takes part in that RFP process. So and in that case as you know, in the three states there would be some load share spreading of that cost over those three states. And each state obviously will be different based upon the specific part of there – either RPS portfolio and our carbon reduction mandates that they have. So that would have to be determined by the three states as part of the RFP process. Andrew Weisel Okay. Thank you. The next question from me DOE’s draft EIS, the cost estimates of undergrounding look quite a bit lower than what you guys have talked about. The most expensive option they have is 4B at $2.1 billion to underground it, is there some disagreement in how they make that estimate, do you still think that it would be prohibitively expensive to underground it or in light of the DOE’s estimate, is that something that you might consider? Jim Judge The numbers that DOE used in their estimates was a direct cost. They didn’t use the fully loaded cost with AFUDC and financing. So they just used the direct cost that’s why their costs were different than our costs. Andrew Weisel So do you still consider – I am sorry continue. Jim Judge The cost that we use are costs that are current industry market costs either for underground that we do or have done and/or updates from our contractors. So we think our costs are pretty accurate. And I think the main difference with the DOE is they just used direct cost. Andrew Weisel Do you still see fully undergrounding as prohibitively expensive? Jim Judge Yes. We see underground – full undergrounding is a necessary, prohibitively expensive and a project – some project modifications could be done with some additional undergrounding that rates, essentially the issue raised inside of the DOE EIS. If you look at the DOE EIS and analyzes essentially three areas; the Northern area, the central area and the Southern are like the White Mountains National Forest. And all of the areas, if you look of the scenic impacts are all rated on the scale from zero to five. They are already either very low or low in terms of the scenic impact. Nevertheless, as a result of that outreach we have done, there is some additional undergrounding that can be done, that will make those numbers even lower without having to underground the entire project. Andrew Weisel Thank you very much. Jeff Kotkin Thank you, Andrew. Our next question is from Caroline Bone from Deutsche Bank. Good morning Caroline. Caroline Bone Good morning, just a minor question really because most of my questions have been asked, but is there anything that could cause you to book a reserve related to the pending second and third ROE complaints, would the ALJ decision be potential catalyst? Lee Olivier There is a potential that the ALJ decision comes on by year end, I think they are targeting in fact at the late December number. And obviously we will assess the merits of that recommendation, whether or not it warrants a reserve or not. So the timing is such that we do expect that ALJ decision at the end of this year. However, the final FERC ruling on it would be the third quarter of 2016. So we will have to look at the facts and circumstances of that order before we could tell you whether it is going to be reserved or not. Caroline Bone Alright. Thanks guys. Jeff Kotkin Alright. Thank you, Caroline. We have no more questions in the queue. So we just want to thank everybody for joining us. We know you have additional calls later this morning but if you have follow-up questions, please give us a call. Thank you very much. Jim Judge Thank you.

Northland Power’s (NPIFF) CEO John Brace on Q1 2015 Results – Earnings Call Transcript

Executives John Brace – CEO Paul Bradley – CFO Sean Durfy – President and CDO Analysts Nelson Ng – RBC Capital Markets Paul Lechem – CIBC Rupert Merer – National Bank Sean Steuart – TD Securities Matthew Akman – Scotiabank Steven Paget – FirstEnergy Northland Power, Inc. ( OTCPK:NPIFF ) Q1 2015 Earnings Conference Call May 12, 2015 10:00 AM ET Operator Welcome to the Northland Power Conference Call to Discuss the 2015 First Quarter Results. During the presentation all participants will be in listen-only mode. [Operator Instructions] As a reminder this conference is being recorded Tuesday, May 12, 2015 at 10 AM Easter Time. Conducting this call for Northland Power are John Brace, Chief Executive Officer; Sean Durfy, President and Chief Development Officer; Paul Bradley, Chief Financial Officer; and Adam Beaumont, Director of Finance. Northland Power management has asked me to caution you that their summary of results and responses to your questions may contain forward-looking statements that include assumptions and are subject to various risks. Actual results may differ materially from management’s expected or forecasted results. Please read the forward-looking statements section in yesterday’s news release announcing Northland Power’s results and be guided by its content in making investment decisions or recommendations. The release is available at www.northlandpower.ca. I’d now like turn the call over to John Brace. Please go ahead. John Brace Thank you very much operator and good morning everyone. The first couple of months since 2015 have been some of the positive in over 25 years at Northland Power. Our transformation from an independent generally focused power producer into an international developer and owner of sustainable energy infrastructure is well underway. We have long defined our business strategy as one of focusing on measured growth that enables us to deliver sustainable returns. Our activity and result so far in 2015 demonstrate that we are applying the strategy with equal parts of boldness and diligence. Paul will provide more detail on our financial results shortly but I can tell you that while our quarterly adjusted EBITDA was marginally lower than the same period last year is result of us taking advantage to some exceptional opportunities in the natural gas market due to high prices last winter our overall results were in line with our expectations. The first three months of 2015 saw a successfully complete over $2 billion of debt and equity financing or taking big steps forward when our European offshore wind portfolio and Ontario renewable projects. In March we closed financing on a total of €1.2 billion for a second 332 megawatt offshore wind project called Nordsee One located approximately 40 kilometers off the coast of Germany in the North Sea. We also closed financing on our 100 megawatt Grand Bend wind project located in Ontario with the projected cost of $384 million. Both Nordsee One and Grand Band are now under construction. Construction is also progressing well on our 600 megawatt Gemini offshore wind project in the Netherlands and our four remaining Ground-mounted Solar projects here in Ontario above which I’ll talk more shortly. Our 2015 focus is on successfully delivering or advancing all of these projects and so far so good I look forward to provide any more detailed presentation on our progress at our upcoming AGM on May 19th I can tell you in the mean time that all construction projects are proceeding well. On Gemini production at the 200 kilometers of electrical interconnection cables which you can see illustrated on the covers of our 2014 annual report is nearing completion and installation out at sea has already started. Almost 90% of the 150 monopile foundations for the turbines have been made in progress on the two offshore high voltage substation platforms is significant. The remainder of the project components are in production and onshore construction is also taking place. As part of our due diligence for Northland and under our rules as members of the Gemini Board of Directors both Paul Bradley and I have been visiting some of the Gemini manufacturing facilities. These have included the electric cable, monopiles, transition pieces, offshore platforms and foundations and the turbine manufacturing facilities. I can tell you that seeing the scale and size of the equipment being produced and the huge number of components that have already been made is extremely impressive. What is most important however is that overall things are progressing well and so far both Gemini and Nordsee are proceeding on schedule and on budget. We are creating infrastructure that will meet the electricity needs of millions of people for many years into the future while supporting the Europe Union’s clean energy transformation. We see a healthy appetite and therefore significant opportunities for this version in technology. In fact a new report from global data indicates that Germany is set to overtake the UK as the global leader for annual offshore wind turbine installations in 2015 with over 2,000 megawatts estimated to be added this year. Globally annual offshore wind installations are expected to more than double and we are excited to be a part of this growing industry. And here at home, well on the smaller scale we’re also building important clean energy infrastructure at our Grand Ben Wind project which is a 50-50 partnership with two first nations. Excavation has already begun along the underground transmission line, the turbines and other major components are on order. Construction will continue throughout 2015 and the project is anticipated to start producing electricity in the first half of 2016. Finally, progress on our four remaining Ground-Mounted Solar Projects, divide into two parts. First is the completion of the construction. As we told you on our last call, Ganotec Inc. has taken over construction on the remaining four projects. Construction on all four sites is progressing well, and they are expected to be complete in 2015. Second, thus a situation with the original contractor H.B. White; whom we terminated at the end of last year for breach of the EPC contract. Expectedly the wait in the number of subcontractors have filed liens and claims on the projects and we have filed our own claims against White for cost, losses and damages for breaches of the contract. It will undoubtedly take some time for these legal matters to be sorted out and we are convinced of the legitimacy of our position. In the meantime the projects will be finished and in production. Despite these challenges, we remain confident that overall, our Ground-Mounted Solar portfolio will meet return expectations and deliver attractive reliable results over the long term. Moving to an update on our long term assets, I’d also like to provide to you an update of the global adjustment phase that affects three of our interior power projects agreements. Back in March, the quarter rolled in favor of Northland and other power producers in relation to the escalators in our power purchase agreements. Disappointingly but I suppose unsurprisingly the ruling was appealed by the contract counterparty. We feel confident that the courts will continue to rule in our favor as the case progresses through the legal system. I am also pleased to remind you that our Kirkland Lake facility has already signed a new 20-year contract for the 30 megawatt gas peaking portion of that generation station. The details of an agreement for the final base load gas field portion of the facility are being papered. We are also working trying to ensure a long future for our Kirkland facility, however as power purchase agreements extension expired as of midnight last night at which time we cease to generating electricity. We’ve not yet permanently shut down the facility or decreased our efforts towards attaining a contract renewal or further extension. Our staff remained employed as we continue to do everything we can to secure a new agreement. We have the support of the community in the region. The facility is critically important to North Eastern Ontario and its forestry industries and our host community in Kirkland. We will continue to work hard to find a solution, building a sustainable future for our host communities translates to a sustainable investment for our shareholders. On that note the quarter has seen significant activity from the financing perspective. As part of the over $2 billion in debt and equity financing that I mentioned at the start, we successfully completed over $400 million of convertible debentures and common share offerings during the first quarter. The proceeds were used to help fund our investments in the Nordsee One and Grand Bend projects. In February, we closed the sale of our interest in the Frampton wind project for net proceeds of approximately $10 million. To achieve our continued growth objectives we are applying our proven strategies on an ever increasing scale. The result is in increasingly diverse portfolio of clean and creating a long term energy assets. I would now like to turn the microphone over to Paul for further discussion on our financial results. Paul Bradley Thank you, John. I’d like to extend my thanks to everybody for joining us this morning. As John mentioned it’s been extremely busy quarter for us. Last night, Northland Power released its 2015 first quarter results. Northland’s plant operations for the most part met or exceeded our expectations for the quarter, with the company generating $97 million of adjusted EBITDA. As John noted, the first quarter of last year that’s 2014, produced exceptionally strong results. The period of high natural gas prices provide us with opportunities to curtail electricity production and resell the natural gas at certain facilities, which created unexpectedly high natural gas resell margins. So as those spikes and gas prices did not recur this year, Northland’s performance reflected the more normal level of operations resulting in a 5% decrease in adjusted EBITDA from the same quarter last year and free cash flow down $50 million, 11% lower. The sites of the non-recurring gas resale’s margins, other key factors that affected our adjusted EBITDA for the quarter included the following. Higher interest income earned on Northland’s portion of the Gemini subordinated debt, inclusion of Mclean’s which became operational in May 2014 as well as the non-recurrence of the write-off of deferred development cost into 2014. These increases to adjusted EBITDA were more than offset by several items. First a onetime charge associated with an IESO generator cost recovery program for Thorold. Second, lower performance incentive fees earned from Cochrane and Kirkland Lake, also may be due to the 2014 gas resale margins. Third, lower investment income largely due to higher dividends for Panda-Brandywine in 2014. And lastly increased corporate management and administration cost. Northland’s free cash flow are 50 million for the quarter were 7 million lower than the same quarter in 2014 for the same reason as a decrease in adjusted EBITDA and largely due to the high level gas resale in 2014. Other factors contributing the lower free cash flow over 2014 include an increase in net interest expense increase primarily due to the inclusion of interest on the claims and Ground-mounted Solar Phase II debt, interest on the convertible debentures from those issued in January and interest on Northland’s corporate term facility; also an increase in scheduled debt repayments from these new debt facilities. These net decreases in free cash flow were partially offset by the net proceeds from the sale of the Frampton wind farm in 2015. Our dividend payout ratio for the quarter was 81% versus 63% in 2014 on a total dividend basis, including the effective dividends invested through Northland’s DRIP program, the cash dividend payout was 60% compared to 49% in the first quarter of 2014. The increase in payout ratio reflects the decreased free cash flow and the new share capital issuances to fund Nordsee One, Grand Bend and in Gemini projects. This is in line with our expectations as we execute on our development and construction program. The GAAP net loss of 26 million exceeded the prior year primarily as a result of the non-cash fair value accounting loss on interest rate swaps at Gemini and Nordsee One. This net loss does not reflect the economic substance of the projects, because the interest rate swaps are used to effectively fix the interest rates at Gemini and Nordsee One. These fair value adjustments are non-cash items that will reverse over time and have no impact on the cash obligations of Northland towards projects. Turning to Northland’s financing activities this quarter. We have continued the vigorous pace of 2014. In the first three months of the year we completed over $2 billion of debt and equity financings as we advanced our projects into construction. To assistant funding our Nordsee One and Grand Bend wind projects, we issued as convertible debenture offering in the amount of 158 million and a common share offering with gross proceeds of 281 million which includes the private placement of 50 million from our Founder and Chairman, Jim Temerty. The funds will also be used to refurnish working capital and general corporate purposes. Approximately 70% of Nordsee One’s €1.2 million project cost will be provided from a non-recourse bank loan for multiple international commercial lenders. Reflecting the strength of the project the financing was over-subscribed and completed in only six months from the commencement of the bank debt process. Late in March, we also completed financing on the Grand Bend wind project. The total project cost is expected to be 384 million and approximately 85% of the projects required financing has been provided by an institutional style fixed rate amortizing loan. The total co-generation bank term loan coming due in September was refinanced for 183 million with its maturity extended to March 2030, with this financing Northland has extinguished all of its project refinancing liquidity risk and has locked in all interest rates towards project debt. Northland also entered into foreign exchange contracts to effectively fix the foreign exchange conversion rate on substantially all projected euro denominated cash inflows from Nordsee One over the fixed cash period. As you can see it was extremely busy quarter for Northland’s financing team. For our financial outlook for 2015 Northland continues to expect our adjusted EBITDA to be in the range of 380 million to 400 million in 2015. We are currently guiding towards the lower end of the range allowing unfavorable outcomes of the contract extension of Cochrane and potentially different interim arrangements on the appeal of the global adjustment court case and should these two items come out as we don’t expect then we have some allowance at our guidance for that. For payout ratio in 2015 we continue to expect the ratio to be in the range of 100% to 115% of free cash flow on a total dividend basis. As we have said in the past Northland’s payout ratio is expected to exceed 100% on a total dividend basis, until Gemini and Nordsee are completed in 2017. On a net basis however, including the impact of reinvested dividends through the DRIP, we expect the cash dividends to be 75% to 85% of free cash flow. As demonstrated by all the financing activity this quarter, management’s continued objective is to effectively manage our balance sheet and minimize the amount of dilutive equity raised while prudently maintaining healthy credit metrics. And with that I will turn the call back to John for concluding remarks before taking your questions. John Brace Thank you, Paul. I believe our results this quarter demonstrate significant progress towards achieving our 2015 commitments. Results are gratifying to see the Northland team’s efforts acknowledged by the international finance and business community through awards from a number of prestigious publications. Some of these we told you about on our last call but here is a summary of all of the awards, Projects Finance International, Power Deal of the year Europe awarded to our Gemini project, Infrastructure Journal and Project Finance Magazine, Win Deal of the Year Europe and overall winner for Europe and Africa awarded to Gemini, Netherlands Canadian chamber of Commerce Northland named 2014 business of the year, Environmental Finance Win Deal of the year of the year 2015 awarded to Gemini and Investor Relations Magazine awarded Paul Bradley, best Investor Relations Canada by our CFO. It has been over 25 years since we opened our first facility in Cochrane, Ontario and we have since transformed into an international power producer. We are now in the period of significant growth and we are focused on successfully delivering in that growth while continuing to deliver on our commitments to our investors. We believe our ability to marry entrepreneurialism and prudence that are focused on effectively managing risk will hoping to forge the worldwide shifts to sustainable energy is helping to divine Northland as a leader an innovator and a company to watch. We have big things ahead of us and we look forward to showing you what were capable of. As we grow, we remained focused on our core promise to deliver sustainable value that our shareholders can depend on today and well into the future. That includes our formal remarks. And would be pleased to take your questions at this time. Operator if you can please hand over questions. Question-and-Answer Session. Operator Thank you. Ladies and gentlemen [Operator Instructions] Our first question comes from the line of Nelson Ng with RBC Capital Markets. Please proceed with your question. Nelson Ng Great, thanks. Good morning everyone. Just the quick question on Cochrane, so if the facility stops running for period until hopefully get another contract are there any issues with the biomass or a gas supply and do you expect the facility to be running mainly on gas if it becomes bigger? John Brace There is several parts to answer my question like Nelson first we are doing our best to make sure that gas supplies and wood supplies will still be available to us when we get to start our facility up again if the plan were to continue on operating as it was than it would be gas and biomass that as it has always been, if negotiations with the government were to proceed in a fashion that it would be turned into a partly peaking facility then one could expect that the gas part of that would be that probably the biomass would continue on in more or less a base load mode we are making sure as from a contractual point of view and a physical point of view that we laying up the facility in the interim period here while we’re now running to be capable of generating well long with into the future. Nelson Ng Okay, thanks. And then I have a few questions about Nordsee One, in terms of send we on the turbines I’m sure that banks are pretty comfortable with the turbines given the financial close has been achieved but can you provide some color in terms of like from your perspective in terms of like the technology risk like I understand the turbines are pretty big like 6.5 megawatts and it’s not that common out there right now and I’m not sure if the website is updated but I think Senvion’s website indicates that there is about 4 off shore in projects with those blades operating so can you just give me a sense of how your perspective of the technology risk? John Brace This very part answer with slide going to a longer one Nelson was there were very comfortable with the turbines it’s in fact one of them Senvion is one of the larger turbine producers for the off shore wind industry. The turbine were using is already been deployed in other wind farms and is in operation and so and has a good track record so there is one known issue to do with the bearing’s on the turbine and Senvion has both the short term fix and a long term program in place for dealing with that and you can bet that in our contract to Senvion their contractual provisions they relate to keeping us immune as it were from any difficulties with the bearing which I think frankly reflects Senvion’s confidence in the future and also center bridge their recent purchase risk confidence in Senvion as a long term performer in the off shore wind industry. On top of that off course as you mentioned the banks and the banks due diligent engineers have been all through it and Senvion’s turbines are the ones we are using for our project and their prior track record come up with good marks. Nelson Ng I see. And then just one kind of follow up question on Senvion, so you mentioned that they were recently acquired I think earlier this year for 1.2 billion. Can you talk about counter party risk and any changes in the direction of the company or the company’s strategy? Paul Bradley Yes. I think Nelson net net we were positively impressed by the [Centerbridge] acquisition, Senvion has always been — and for those who don’t know Senvion is rename of REpower and everyone knows REpower is one of the first turbine companies in the wind business and they’ve always been a consistent performer year-over-year and a very solid technology. With [Centerbridge’s] acquisition it basically took a very weak and unhealthy pattern out of the picture and the concern always was hate as the company get rated or the assets gate rated to help the weak pattern. The acquisition and we were pretty to a number of the dates around the acquisition from both [Centerbridge] and the company, but the company actually has a number of protections in place that put us in a much better position overall. And also the acquisition price reflects the strength of Senvion’s ability to produce income. So I think once we got through all of our due diligence of the acquisition we were net net very happy about the file. Nelson Ng Thanks, Paul. And then just one last question relaying to your general overhead cost I think management and [win] cost have increased, I was just wondering in terms of I guess directionally do you expect those cost to continue to increase over the next few years with the two offshore wind projects I guess being commissioned in 2017. And then also I wanted to ask whether the development cost will kind of ramp up going forward and whether you’ve started spending development cost in Latin America yet? Paul Bradley I’ll talk about the first one, we’ve been over the past year but probably back end loaded to earlier in 2015 has been building in the necessary infrastructure to take us from kind of a fairly small Canadian base company to a company that’s positioning itself to be powerhouse in a much broader market and much bigger project. So that as you can imagine take some infrastructure from systems and compliance and all kinds of internal folks. So you’re seeing us walk away through that I certainly wouldn’t want — all believe for a moment that’s a trend but there is a bit of the step that we’re going through at the current time for the overhead cost. We’re seeing some good productivity coming out of it and from the risk management standpoint and from other elements that it’s the right thing to do and it was time for us to do some of it. So period no time like the present to make those investments. I’ll let Sean cover from the development side, Sean Durfy, our President and Chief Development Officer. Sean Durfy Thanks, Paul. Nelson, from the perspective of development costs our costs are in line and somewhat lower actually due to development expenses than we had last year. And we’re also very prudent in how we go about spending development cost once we get further into the development cycle. When it comes to Latin America we’re still very much in the origination stage of development so very little excessive cost going into that, in other words we don’t have foreign deals yet. So we’re still very much in the origination phase so lower expense cost. Operator Our next question comes from the line of Paul Lechem with CIBC. Please proceed with your question. Paul Lechem Thank you. Good morning. I’m just wondering for Cochrane, if the plant remain shut down for the balance of Q2, what should we expect in terms of cost just to maintain that facility until potentially a new deal is struck? John Brace Paul, we’re not going to nearly go into that I mean Cochrane is less than 2% of our current take on everything no matter what you do to it. So we haven’t really tried to pull us out as you can imagine there is some competitive attention here with our off take or not disclosing orderly on our financial information so if don’t mind we’ll passing that question. Paul Lechem Fair enough. On the Brand Bend still, bit of an update in the last call you gave an update — expected to build the project, is that number that you gave last quarter that still what you believe you can bring these facilities in under. John Brace Yes. Paul Lechem The 75 to that 13 project is still help? John Brace Yes. Paul Lechem Okay. And lastly on Gemini, can you give us over the next few months what milestone should we expect maybe between now and the next call on the Gemini construction. Thanks. Paul Bradley The main thing that will happen on July 1st under our environmental permit were allowed to start installing the monopile foundations for the turbines. So on our next call presumably we’ll be able to tell you something about the number of foundations that have already been late. In addition to that there should be fair amount of the offshore cable, the export cable about 200 kilometers of undersea cable I mentioned in the earlier remarks laid on the ocean floor and depending on the exact timing we may be close to sending the offshore platforms out to sea but can’t remember when our next call is actually scheduled for the date, it’s August so they should be out. Operator Our next question comes from the line of Rupert Merer with National Bank. Please proceed with your question. Rupert Merer So looking at your construction pipeline as a few projects moved to financial close. [I imagine] you put all your equity into those projects today, is that correct? John Brace That’s correct. Let`s say typically Rupert the banks insisted the equity goes in first. Rupert Merer Right, so sounds like your approach going well, so given where you are now and what you’ve learned over the last few quarters, what keeps you up at [night] today with those projects if anything and already you see [indiscernible] risky or you’re scheduled on budget today? John Brace That’s pretty wide reaching question. I think from my perspective, we are confident that all of the projects which are under-construction will meet their schedules and budgets. What we have to do as the owners, is make sure in the case of Gemini and Nordsee, whether actually large teams of people that are the owners side of the table over in Europe watching that the contractors do what they’re supposed to do with a right degree of quality and the right rate level of health and safety and environmental protection and cost control that the projects unfold. So from Northland’s point of view our role to a large degree is ensuring that our two teams of 40 odd people in Europe perform and watch the contractor the way they are supposed to do. In the case of North America here for Grand Bend’s we have a classical balance plan contract with [indiscernible] and we are — our role is much closer to the home in terms of watching them and making sure they do what they are supposed to do. And off course in the [indiscernible] we are in slightly different relationship now with [indiscernible] than we were with White, so we are paying close attention to scheduling cost on those projects. So the shorter form version of it is, I wouldn’t say, it keeps me up at night in a frightened state by any means but as owners, we have to make sure that we absorb these projects and influence these projects to best we can to make sure they stay on schedule and on budget. And off course overwriting everything is the need and the absolute necessity of clean health and safety records and environmental records on those projects. Rupert Merer Yes, great, thanks, just a quick follow up on Nelson’s question, in early classification of Nordsee and Grand Bend, from development of TPNA, will you see a decline in your development cost for the rest of the year? John Brace I think, remember our business is one big pipeline. Absolutely after continue to develop, but we do it prudently, right now we don’t have any projects in the stage of where Nordsee was six months ago, so we’ll continue on the origination side and continue developing deals and really it’s the Nordsee shows the most promise over the short term. So our development budget is what it is and as I said it’s a touch lower than it was the previous year. Operator Our next question comes from the line of Sean Steuart with TD Securities. Please proceed with your question. Sean Steuart Couple of questions, with respect to Phase III of the Solar, I think the wording in the MD&A was you’re not in a position to determine expected final returns but you do expect it to reach minimum hurdles. I guess just with products underway here and it seems like a fair degree certainty on CapEx. I’m surprised you aren’t able to nail that in, is it just with respect to the ongoing legal proceedings with the former contractor? John Brace Yes, that’s a main part Sean, as in our view we’re very convinced of the legitimacy of our position as I mentioned earlier on, it’s how much money that White ends up pawning up to the table and [that is, we’ll be able] to fight to get there, so that’s a fairly uncertain number at this stage. Paul Bradley And that’s why we put the outside barrier number in there Sean, just to let people get a sense of where we believe the worst outcome comes and then Sean, we believe we’ll do better than that, but we feel it’s responsible for the outside number. Sean Steuart Okay, understood. And then on Kirkland Lake, can you give us any context on the economics for the TPA for the 30 megawatt peaker? John Brace With rather which we get the whole package done because we’re in the middle of a very commercial sensitive negotiations, so let us defer that if you don’t mind Sean? Operator [Operator instructions] Our next question comes from the line of Matthew Akman with Scotiabank. Please proceed with your question. Matthew Akman Good morning. Paul I wonder if you could just recap the [thorough] refinance terms versus prior any advantages in the refinance terms relative to what it was in place? Paul Bradley Yes, so basically a largely awash, we didn’t over finance it, [indiscernible] plenty of money out and if you realize the interest rate had been swapped out there really was no gain on the underline and [indiscernible] was done at a time when spreads were at historical low so the spreads were ted higher than that we had before but we are also able to pick that up in better amortization of the final debt so from a free cash flow perspective the financing kind of kept us about the same maybe as snick below where you were but nothing was mentioning. Matthew Akman Good was the amortization disclose? Paul Bradley Well. Typically we do disclose it I don’t believe we’ve come out with an area since we’ve done that as typically we will put it there but it’s basically closer at the end of the life with the PPA along with CAF I think if you go back if you want to get the exact one you can pull out what the institutional change was amendment [Indiscernible] Matthew Akman Okay. Thank you. In terms of the FX hedges and the projects finance on North Sea can you make any comments about where you hedged out versus your expectations for returns and your project analysis going in. Paul Bradley While we hedge we typically look at our projects pre-hedged only to keep the discipline of trying to make the hedging decision as a corporate decision not a project decision because it’s really the corporate investors that are enjoying those cash flows not the project per say. What I can tell you is that the euro cad forward swap rates tend to still be very favorable versus just a plain forward spot rates so in other words we will have picked up a fair bit of return over the course of time if you kind of take the swap and marry it up with the actual project cash flows but again I would like to reiterate that we keep the corporate hedging transactions we try to keep that little bit separate from the actual project transactions. Matthew Akman Okay, thanks for that. And finally is it too early to talk about contingencies on Gemini and North Sea and whether you have started to chug and to those at all at a normal pace or do you waits for another 3 months to 6 months to start hearing about that? John Brace By thinking the case with North Sea it’s too early for sure in the case with Gemini and we’ve been under way for a year now there has been a small use of contingency but nothing significant at this point in time. Operator Our next question comes from the line of Steven Paget with FirstEnergy. Please proceed with your question. Steven Paget Thank you and good morning. Gentlemen off shore wind went from a technology or skill set that was expensive to something that was economic and could be brought in on time on budget and that’s when Gemini and North Sea team in the picture am I correct. Unidentified Company Representative Yes. Unidentified Analyst So what three technologies are coming in that you will be looking at as in that off shore wind renewable or power generation technologies that are just becoming economic and you saw. Paul Bradley I’ll start and then John can jump in. I think the Steven we are sort of 15 years into the commercial application of off shore wind so it’s still a very young industry and I think there is incredible potential still in the off shore wind space be it in the North Sea another parts of the world so our concentrated development efforts have been continue to look at that technology the company was started on the basis of thermal technologies and we still see plenty of opportunities there as well and off course with solar we’ve got our first solar plant in Latin American countries, solar is becoming closer to grid parity and a lot of opportunity there as well, so leading edge technologies I don’t know I could let John answer it but from my perspective and a development perspective I think we got lots of opportunity in those three technological fields. Unidentified Company Representative Well just before [Indiscernible] oracle of the future I just like to remind everybody that we are kind of an infrastructure company so we aren’t even looking to necessarily be cutting edge on new technologies we to your point Steven we did enter an off shore wind when it was at the point that we felt the maturity was sufficient and probably the rest of the world thinks it’s a bit early and there end lies the superior returns that you can get at a certain technology but as when it comes to things like wave technology or some of the storage ideas are out there I think you would certainly wait for them to mature that before you saw a stuff filing in those areas and now John Brace. John Brace I think maybe on the one thing to add to elaborate a bid on something Paul just mentioned storage as a lot of stuff going on and storage with all search of different technologies but I would just like to remind everyone it doesn’t need to be new technology to solve the misuse of the day and those are of project which is from storage are very old technology or very proven technology and wonderful project so you don’t really need new technologies to move the ball down the court on the developments and improvement of the electricity generating system. Operator Mr. Brace there are no further questions at this time. I will turn the call back to you. John Brace Thank you very much operator and everyone for joining us today. We will hold our next call following the release of our second quarter results in August and we look forward to talking to you then. Thank you. Operator Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and have a pleasant day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com . Thank you!