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GreenHunter Resources (GRH) on Q3 2015 Results – Earnings Call Transcript

GreenHunter Resources, Inc. (NYSEMKT: GRH ) Q3 2015 Earnings Conference Call November 16, 2015, 10:00 AM ET Executives Serene Prat – Head of IR Kirk Trosclair – Executive Vice President and Chief Operating Officer Ronald McClung – Chief Financial Officer Operator Good morning, ladies and gentlemen. My name is Latisha and I will be your conference operator today. At this time, I would like to welcome everyone to the GreenHunter Resources Third Quarter 2015 Financial and Operating Results Call. All lines have been placed on mute to prevent any background noise. [Operator Instructions] Thank you. I would now like to turn the call over to Mr. Kirk Trosclair. You may begin sir. Kirk Trosclair Thank you, operator. Good morning everyone and thanks for joining our third quarter call today, Monday, November 16. And before we get started with the operational results and the financial results, I’d like to have Serene Prat read the Safe Harbor statement. Serene Prat Good morning. Thank you, Kirk. Before we begin with the content of today’s call, I’d like to advice you that today’s call may include forward-looking statements within the meaning 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 risks 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. Thank you. Kirk Trosclair Thank you, Serene. We’ll go ahead and get started this morning and basically just give you some highlights of the third quarter, look at the three months and the nine months ended September 30. But before we go into that, let’s just grab the overall picture. From last year at this time, WTI prices are now over 52% or so down year-on-year and the rig count itself is down over 50% as well. So you basically understand what that translates to as far as production and drilling in completion fluids is in the work space, on the environmental services side and the shale water outlook side. We’ve had some continuous growth over the last few quarters, continuing from the first quarter when we were averaging somewhere around 250,000 barrels a month or so of injection, and in the second quarter that went up to 275,000 on average, and in the third quarter we’ve averaged around 360,000 barrels per month. So the biggest thing there was, if you guys remember, right at the end of the second quarter and going into the third quarter, we added two additional wells down at our Mills Hunter facility, and results of those wells were really good for us and that helped translate that to a good third quarter on volumes. Even though we turned the wells on the first week of August, we didn’t get the ramp up until we finally got most of the injection volumes two or three weeks later. So we finally saw that going into August and September. So that’s the disposal volume side, on how it’s going so far this year. The trucking side has basically done a little bit less exciting than the disposal side. We started seeing price pressure on transportation in the middle of second quarter and that’s continued into the third quarter. We had, from the first quarter, we had 8,000 hours or so of trucking; second quarter, we averaged 6,500 hours or so per month; and in the third quarter now, we’re around 5,000 hours or so per month. We’re staying diligent in adding new customers out there in the Marcellus and the Utica area that should help to increase some of our volumes. But it’s – like you guys can imagine, it’s mostly production volumes at this point. Every once in a while we’ll have a flow back coming in from someone that maybe fracing a well, but there’s not that many completions going on. So our report, I think, the completions behind the pipe now are up over 5,000 wells and that’s just unheard of today. So I’ll jump into the press release portion and hit some of the operational highlights before I turn it over to Ron McClung on the financial side. Obviously, first of all, we did have positive adjusted EBITDA of $482,000 for the third quarter. The injection volumes, as I just mentioned to you, basically only about a 10% decrease respectively year-on-year and being the majority of that is production volumes, that’s pretty steady and it’s – what we can look forward to, I think, as the new norm right now until things turn around. We’ve already talked about the wells, but the two wells that we turned on at the Mills Hunter facility basically were 6,000 to 8,000 barrels per day each well. And that effectively raised our total disposal capacity by 50%, which now takes us to about 21,000 barrels per day of injection capacity currently at this time. We have a couple of other wells getting ready to go. We’ve got one in Ritchie County, West Virginia that we should add and turn on here in the next week or so, couple of weeks. So you’ll see that one come on in the fourth quarter of 2015, and then we’ll add one of the additional wells at Mills will come on as well in the fourth quarter. The last well at Mills, we’re looking at now probably in the first quarter of next year before we turn that on. In the last Q, we had just ordered those trucks. We have received the eight new Peterbilt trucks, 407s, and out of the trucking transportation side, the pricing pressure has not hit the 407 trucks compared to the straight water trucks, so that’s a good sign and we continue to put those on the road every day. Also, we looked at our revenues, and based on our injection volumes, we looked at our current portfolio and how it lays out between our number of customers that we have in the Appalachia Basin and no one customer is more than 21% of our total revenue up there. So one other thing we’ve done is pulled back on the G&A; we went from $2.1 million in the third quarter last year to $1.5 million third quarter this year. So that’s another decrease of 29%, and we’ve pulled on the belt just about as tight as we could possible pull on and cutting cost everywhere we can, but still trying to keep our customers happy and work in a safe and prudent manner. So with that, those are most of the highlights from the third quarter, I’ll let Ron take over and go through the financial results and we’ll follow that up. Ronald McClung Thank you, Kirk. I’m not going to rehash the bullet points that are in the press release related to EPS. I will get right into some of the financial results. Revenues for the third quarter in total were $4.5 million for the 2015 third quarter compared to $6.3 million for the third quarter of 2014, or an overall decline of 28%. However, our operating losses declined to $649,000 in 2015 for this quarter versus $1.2 million in the same quarter in 2014. As we expected and had disclosed previously, we did not move some of our debt covenants for the third quarter of 2015. These covenants had previously been waived by our lender for this quarter. Notably, as we previously also announced, we did not pay dividends for any of the months in the third quarter of 2015. Our amended agreement with our lender does not allow us to pay dividends until we’ve been in compliance with our covenants for two consecutive quarters. With the current state of the oil and gas economy, we do not anticipate paying dividends in the foreseeable future barring a significant change in the business environment, and we’re not able to predict when such a change will occur. For the first nine months of 2015, our revenues were $14.3 million versus $21.6 million for the same period in 2014. A key factor in managing our business relates to direct margins, which we define as revenue less direct cost of goods and services provided, and then what percent that direct margin is when compared to our revenue. Even with this 34% drop in revenue, our direct margin actually increased to 40% in the first nine months of 2015 compared to 33% in the first nine months of 2014. This improved margins in spite of the current business environment is a positive reflection on our management’s ability to cut costs. Looking a little closer at the current quarter results, our disposal revenue was about $3 million this quarter compared to about $3.4 million in the same quarter in 2014, or a decline of about 13%. This decline was partially the result of a 5% decline in this quarter last year in the number of barrels we disposed. And as Kirk said, this was mainly due to a dramatic drop in flow back order from last year and also due to some wells in our service area that are being shut in due to low commodity prices. We’ve offset [indiscernible] as Kirk also mentioned, what could have even been a greater decline in revenue by adding some new customers in the third quarter of 2015. With revenue being down 13%, volumes are only being down 5%, the remaining 8% of the decline was due to a decline in our average revenue per barrel of about $0.29 when compared to last year due to the downward pressure in processing we’ve experienced while trying to maintain and even grow our market share in this difficult environment. Internal trucking revenue was about $1 million this quarter compared to $1.2 million in the previous year due to market conditions that have led to a decline in trucking hours and again a downward pressure on processing. Skim oil revenue was down to $87,000 this quarter compared to $198,000 last year, mainly due to lower commodity prices. Now, some comments on the cost side of our business for this quarter. Our disposal cost in the current quarter, in spite of only seeing a 5% drop in volumes, we were able to decrease costs by about 16% from last year due to operational cost cutting measures. Our trucking costs declined about 20% from the same period last year and we were able to maintain our direct margins at about 43% for both this quarter and the third quarter of 2014, in spite of an overall 28% decline in revenue from last year due to these cost cutting efforts. As one might expect and as Kirk has already noted, we’re leaving no stone unturned in looking for ways to lower our costs in this environment. We were able to cut general and administrative costs by about 46% when comparing the current quarter to the same quarter in 2014, while a little more than half of this savings was due to a decline in non-cash stock compensation. The company also had substantial declines in payroll related costs and smaller costs in G&A, again, mainly due to our austerity efforts. The company continued to cut costs in the third quarter of 2015 and some of these more recent costs particularly in operating payroll were late in the quarter and thus not much of a benefit to the current quarter. We should see more favorable results from these latest cuts in the fourth quarter of 2015. And finally, as I’ve already noted, we did not see current market conditions allowing us to meet our debt covenants in the near future. This outlook has caused us place on applicable accounting rules to classify all of our new $13 million debt as a current liability at September 30, 2015. That in turn has resulted in adding language to our 10-Q [indiscernible] as to our ability to continue as a growing concern. Kirk? Kirk Trosclair Thank you, Ron. Before we go to questions, let’s just – I guess, I want to go through the third quarter one more time and highlight the additional wells that we turned on at the beginning of the quarter and that took us from 15,000 or so a day over 21,000 barrels of day of injection capacity. And if you look back a year ago, prior, if we’d had the wells owned at that specific time, we would have been at 100% utilization on all of these wells, the new wells that we’ve turned on. But as you noticed in the past, what we’ve reported, we’ve always stayed pretty true to it that we had about 75% of our volumes were production volumes, the other 25% or so was completions volumes. And completions market has just dried up, so basically seeing all the injection volumes that we have and then what we reported in the quarter, the majority of that is production volumes. So a good part is if you can find any silver lining in the commodity price market is out there that production volume is pretty stable and we’ve seen it week over week and continuing through the fourth quarter, I don’t see much change outside from the volumes and trucking hours, things have stayed pretty flat. Outside of that, operator, I think we’re ready to go take a couple of questions. Question-and-Answer Session Operator [Operator Instructions] Your first question comes from the line of [Tony Kaylin]. Unidentified Analyst Can you tell me how – you mentioned your debt covenants not being in compliance, can you talk about what you’re going to try to do to amend those or get in compliance? And in conjunction with that, your $2 million requirement to fund additional equity and I guess [indiscernible] you have a line with him, is that still available? Kirk Trosclair Yes, the line is still available, and we have to – the current amended waiver allows us to raise that capital that equity by December 31, 2015. We are already in talks and negotiations with our current senior lender to modify those agreements at this time. So we’re working on those as we speak. Unidentified Analyst Can you go so far as to characterize, do you believe you will be successful in modifying those or –? Kirk Trosclair We’re working with the lender, that’s pretty much all I can say at this point. Operator Your next question comes from the line of [Bryan Butler]. Unidentified Analyst On the disposal volumes, so assuming that 75% is from production, 75% was in the past from production, does that mean that 21,000 barrels a day capacity that you exited third quarter at, is that basically at 75% utilization, is that the way to think about that? Kirk Trosclair No, that’s our available injection capacity currently today. We’re not operating at 100% utilization on that 21,000 per day. In the third quarter, we had a couple of really good weeks where we averaged over 15,500 or so a day for several weeks, but it’s fluctuating up and down anywhere from the 12,000 to 15,000 per day on average right now. Unidentified Analyst And that’s all produce volume? Kirk Trosclair Pretty much all produced water, that’s correct. We have maybe – a couple of the companies out there had a couple of flow backs, but I can only remember one or two in the third quarter. We do have some anticipated flow backs coming in the fourth quarter that we’ve identified, our customers have reached out to us and told us to expect some heavy volumes towards the middle to late December where they have a couple of wells they are trying to get online before year end. Unidentified Analyst So produce volumes is running in that – I think you’ve just said that 12,000 to 15,000 per day and then the new capacity that you’re adding in the fourth quarter and the first quarter of 2016, I mean, it’s just capacity that’s going to be… Kirk Trosclair This capacity is waiting for the uptick. Unidentified Analyst So, it is not going to be adding anything. On the new trucks that you added, did they contribute at all in the third quarter or is that all talking about fourth quarter and 2016? Kirk Trosclair Only two of the trucks contributed to the third quarter numbers. The rest of them will be contributed in the fourth quarter. Unidentified Analyst What kind of contribution can we expect in the fourth quarter in the current environment? Kirk Trosclair On the 407 side, I think we’ll see steady runs with the 407s. That market has not really declined, but the older straight trucks and just plain water trucks, the pricing pressure that we’ve seen, it will definitely be down again in the fourth quarter. Unidentified Analyst So even though you have new trucks coming on, the pricing pressure you’re seeing is going to be offsetting any benefit that you’re getting from the new 407s? Kirk Trosclair That’s correct. That’s a safe way to look at it. Unidentified Analyst Can you talk about the competitive environment? I know you talked a lot about the market being very difficult and pricing being there, but are we seeing any competitors exiting the market here? I mean, is there some silver lining of – as competitors exit, there is additional volumes to be picked up? Kirk Trosclair We have not seen that, Bryan, at this point additional competitors closing the door or leaving the market, not at all. We haven’t seen it at all. Unidentified Analyst Because there is an expectation across all the providers, that there is going to be some kind of a recovery or is everyone just else — have a balance sheet that can support this? Kirk Trosclair There’s only two other public companies out there and they just published their results last week. I mean, everybody – the other shops out there are basically private shops, so we don’t really know what’s going on in there. But they’re experiencing the same pressures that we are, I’m pretty sure of that. Unidentified Analyst Last one just on the covenants, can you just outline what the covenants are that – current, I know you are renegotiating potentially, but what they are now, where you stood on those covenants at the end of the third quarter? Ronald McClung The biggest challenge in our covenants is there is a covenant that we have to have enough EBITDA to cover our debt source [ph], and that’s about – we now are paying principal payments to our new amortizing loan of $13 million. So that’s roughly $1.5 million a quarter and we did not obviously have that much EBITDA. And so until we’re able to cover that, we’re not going to pass that covenant. Unidentified Analyst So that’s principal and interest on that $1.5 million, what we’re talking about, it’s not just the interest? Ronald McClung Yes. Operator Your next question comes from the line of [Jim Collins]. Unidentified Analyst Question on one of your customers, you probably guess which one, Magnum Hunter, they had some language in their 10-Q that they are having some difficulties with [indiscernible] infrastructure and I just want to know if there’s been – as of this point, any disruption in your business with Magnum, obviously that would be production water at this point, not flow back. And how you look at that going forward for the rest of the fourth quarter? Kirk Trosclair Jim, we have not experienced any delays or anything different on the Triad Hunter side, we’re still taking in their production volumes currently today, but overall, the percentage of revenue and percentage of volumes that have come in from Triad versus the rest of our customers has dropped significantly over the last couple of years. But outside of that, it’s still status quo. Unidentified Analyst You mentioned that one of your customers is 21% of your volumes, I mean based on what you just said, can we assume that that’s not Triad, that’s a different customer that’s 21%? Kirk Trosclair We’ve got several that are floating right around the 18%, 19%, 21%, but it’s not Triad’s percentage. Unidentified Analyst And on pricing, we’ve used $3 a barrel as a benchmark. Given the slowdown and the low rig count in Appalachia, is that still – are you guys able to hold $3 basically? Kirk Trosclair On a blended average, it’s still right around $3, actually in some cases it’s a little over $3, Jim. But yes, you’re correct, since the market has come down, commodity prices have dropped – we’ve seen a turn on pricing pressure getting closer to that $3 range. Operator [Operator Instructions] Your next question comes from the line of [David Rothschild]. Unidentified Analyst Most of my questions have been answered. I guess the one I did have, I assume in the condition you’re in right now, any further capital expenditures at this point are pretty much put on hold, is that correct? Ronald McClung For the foreseeable future, that’s correct. I mean, and that’s why we’ve delayed some of the wells over at Mills Hunter, we just really – we have one of them ready to go, but we just have slowed that down because our capacities are – the injection volumes are not meeting our current capacity at today’s levels. So no need to rush into another well. Unidentified Analyst Have you had to lower your prices quite a bit to keep the business that’s been coming in? Ronald McClung We’ve had to remain competitive and get aggressive with some of the newer pricings and some of the newer contracts. But for the most part, as we just mentioned, the blended rate is still north of $3. Operator And there are no more questions at this time. Kirk Trosclair Thank you, operator. This will conclude our third quarter conference call. Everyone have a good day. Thank you. Operator Thank you. This concludes today’s broadcast. We ask that you now disconnect. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. 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Closed-End Target Date Muni Bond Funds Have A Good Yield And Low Interest Rate Risk

Blackrock and Nuveen target date funds pay back upon maturity. These funds hold pretty safe municipal bonds. These fund have decent yields. Blackrock (NYSE: BLK ) and Nuveen have a series of closed-end municipal bond funds that have a target date maturity. These funds have a nice yield and pay back principal in just a few years. We will look at the Blackrock Municipal 2018 Term Trust (NYSE: BPK ). As of today, it is trading at $15.50 and is almost at par with its net asset value (NAV). That means that the underlying portfolio of cash and bonds are worth what the market capitalization is. The portfolio holds 124 different issues of municipal bonds. They appear to be revenue bonds with names like: New York State Dormitory, California Waste, and Maryland Transportation. Revenue bonds are backed by the revenues generated from a certain project like a toll road or student housing. The bonds are rated: 6.9% AAA, 21.4% AA, 41% A, 18.9% BBB, 5.2% BB, 3.3% not rated, and 3.3% cash. The portfolio is only 1.5% leveraged, meaning that in a closed-end fund, that is all that has been borrowed. The fund has returned 5.8% since it was taken public in October 2001. Most of the time, it trades at par to NAV except when the markets went crazy in ’08 and then recovered. The trust yield 4.7¢ a month, so the total yield is 56.4¢ a year divided by today’s market price of $15.50 for a yield of 3.64%. The bonds will be liquidated or will have matured by December 31, 2018. That’s a pretty good yield for a bond that matures in about three years. The maturity price is $15. I assume that there could be some cash left over. The internal fee is 0.64%. It does not appear that there are many funky bonds that could go under. These include Detroit, Illinois, and Puerto Rico government obligations. As the bonds in the portfolio are backed by specific projects, they appear to be pretty safe. I must say, it’s seems like a pretty good investment for certain circumstances. As bonds are sold in $1,000 increments and the minimum that most bond brokers require is to buy in a $5,000 a lot, an investor must have quite a bit of money to hold a diversified portfolio. These Blackrock funds are good to hold smaller amounts of cash that are low risk, provided that the trade fees don’t negate the returns. These funds are traded like stocks. Other funds that fit in this category include: the Blackrock Municipal 2020 Term Trust (NYSE: BKK ), the BlackRock New York Municipal 2018 Term Trust (NYSE: BLH ), the Nuveen Intermediate Duration Quality Muni (NYSE: NIQ ), and another Nuveen Intermediate Duration Municipal Term Fund (NYSE: NID ). I have not done the research on these as I have on the Blackrock listed above. I have also not looked at the prospectus and just looked at the fact sheet. The particular closed-end fund seems to have a decent return and should do well in a rising interest rate environment. It would be nice if the fees were a little lower but what can you do? A yield of over 3% with a maturing of three years is pretty good in this environment.

Algonquin Power & Utilities’ (AQUNF) CEO Ian Robertson on Q3 2015 Results – Earnings Call Transcript

Executives Chris Jarratt – Vice Chairman Ian Robertson – CEO David Bronicheski – CFO Amanda Dillon – IR Analysts Nelson Ng – RBC Capital Markets Rupert Merer – National Bank Sean Steuart – TD Securities Ben Pham – BMO Capital Markets Paul Lechem – CIBC Jeremy Rosenfield – Desjardins Securities Inc. Algonquin Power & Utilities Corp ( OTCPK:AQUNF ) Q3 2015 Results Earnings Conference Call November 6, 2015 10:00 AM ET Operator Good day, and welcome to the Algonquin Power and Utilities Corp Q3 2015 analyst and investor call. Today’s conference is being recorded. At this time I would like to turn the conference over to Mr. Chris Jarratt, Vice Chair. Please go ahead, sir. Chris Jarratt Thank you. Good morning, everyone. Thanks for joining us on our 2015 third-quarter conference call. As mentioned my name is Chris Jarratt and I’m the Vice Chair of the Board of Directors at Algonquin. Joining me on the call today are Ian Robertson, our Chief Executive Officer, and David Bronicheski, our Chief Financial Officer. For your reference, additional information on the results is available for download at our website. On the call today we will provide additional information that relates to future events and expected financial positions that should be considered forward-looking. Amanda will also provide additional details at the end of the call, and I also direct you to review the full disclosure on the quarterly results page of our website. This morning Ian is going to start with a discussion on the highlights of the quarter. David will follow with a review of the financial results, and then we’ll open the lines for questions. And we ask that you restrict your questions to two and then re-queue if you have additional questions to allow others the opportunity to participate. And with that, I will turn it over to Ian Robertson to review the quarterly results. Ian Robertson Thanks, Chris. Appreciate everybody taking the time today. It’s a blustery, rainy day here in Toronto and I guess given that we have hydro, wind, and solar facilities two out of three ain’t bad in terms of our production. But in summary for the quarter, we believe that the strong quarter results that we’ve posted are evidence of the continued solid growth in the earnings and cash flows from our generation and distribution businesses. We think that this type of growth is clearly the underpinning support for future dividend increases, and frankly it’s the basic investment thesis for Algonquin Power and Utilities Corp. During the third quarter, we realized a 70% increase in adjusted EBITDA, delivering 70.2 million versus the 41.4 million reported during the same period last year. Earnings per share growth was equally meaningful, with $0.06 per share this quarter comparing favorably to the Q3 2014 results. With $0.31 of earnings per share a year-to-date and a strong seasonal quarter in Q4 for us, we are cautiously optimistic regarding the ability to meet or outperform the current consensus earnings estimates for 2015. The year-over-year growth reflects contributions from our regulated and non-regulated business groups, with three renewable energy facilities having achieved commercial operations, positive rate case settlements within our distribution utilities, and the impact of a stronger U.S. dollar for the third quarter. The generation business group experienced natural resources in the third quarter that were lower than long-term averages. It’s a theme that appears somewhat consistent across the IPP sector with some blaming it on the El Nino impact. But happily more than offsetting this naturally occurring volatility the distribution business group had a great quarter, with a 20% overall increase in net utility sales and a 45% increase in operating profit primarily attributed to the implementation of recent rate cases. We believe that this yin and yang proves the effectiveness of the diversification strategy on which our portfolio is founded. So with that little summary of the quarter, I’ll turn things over to David to speak specifically to the Q3 financial results. David? David Bronicheski Thanks, Ian. Good morning, everyone. We’re very pleased to be again reporting strong quarterly results. Our focus on growth is clearly evident. Our adjusted EBITDA in the third quarter totaled $70.2 million, a 70% increase over the amount reported in the same quarter a year ago, which is primarily due to the impact of rate case settlements, commercial production at our St. Damase and Morse wind facilities and Bakersfield I Solar Facility, as well as the stronger U.S. dollar. Adjusted EBITDA for the nine months of 2015 was $266 million, a 29% increase over the amount reported for the nine months of 2014. The benefits of our diversified portfolio of regulated distribution utilities and independent power generation are clearly proving their worth. Moving on to some detail from our operating subsidiaries, in the generation group for the third quarter of 2015, the combined operating profit of the group totaled 35.5 million as compared to 24 million during the same period in 2014. For the nine months, the operating profit of the Generation Group totaled 27 million as compared to 108 million during the nine months of last year. During the third quarter of 2015, the Generation Group’s renewable energy division, which consists of wind, hydro, and solar facilities, generated electricity equal to 93% of long-term average resources, which is up significantly from the previous year. And this increase was primarily due to higher wind resources realized in Canada and the U.S. as compared to the previous year. For the nine months, our renewable energy division generated electricity equal to 90% of the long-term average, compared to 92% a year ago. Moving on to our Distribution Group, in the third quarter of 2015, the Distribution Group reported an operating profit of $32.6 million compared to $22.5 million reported in the same quarter a year ago. The increase in operating profit is primarily due to the impact of rate case settlements as well as contracted utility services. Contracted utility services represents an ongoing source of revenue for Liberty Utilities. This consists of utility services provided on U.S. government owned territories where the operating paradigm requires us to provide utility services under contract rather than through regulated tariffs. In the nine months of 2015, the Distribution Group reported an operating profit of $130.7 million as compared to $108.7 million for the nine months of 2014. Now to touch just briefly on our recent financing activities. On July 15, the Distribution Group issued $70 million of notes representing the second of two tranches of our $160 million senior unsecured financing of April 2015, where we were able to achieve a 30-year private placement with a coupon of 4.13%. The notes have been assigned a rating of BBB high by DBRS. The financing is the fourth series of notes issued pursuant to Liberty Utilities master indenture. I will now hand back things over to Ian. Ian Robertson Thanks, David. Before we open up the lines for questions as is our practice, I will provide you a quick update on some of our growth initiatives. And I will start with the projects that we have under construction. Our 200 megawatt Minnesota based Odell wind project commenced construction in mid-May of this year, and we’re pleased to report that currently all 100 turbine foundations have been completed and the first tower was erected this week. Transmission lines complete, construction of the substations is well underway. The first turbine is projected to deliver energy to the MISO grid in mid-January of next year, with commercial operations in the entire facility scheduled for early next year. I will mention that agreements were finalized during the quarter for the provision of certain tax equity financing to the project. The 10 megawatt Bakersfield II Solar Project, adjacent to our 20 megawatt Bakersfield I Solar Project, is now under construction following the granting of the final building permits during the quarter. Commercial operation is scheduled to begin in the fourth quarter next year. And lastly, during the quarter we were pleased to add another project to our portfolio with the addition of the 150 megawatt Deerfield Wind Project. Construction has now commenced on this project located in central Michigan. Energy from the project will be sold pursuant to a 20-year power purchase agreement with the local electric distribution utilities. Switching to the development pipeline of opportunities, the 75 megawatt Amherst Island Wind Project, located down near Kingston, received its approval to proceed with the issuance of the Renewable Energy Approval, or REA as it’s called, in August. The expected appeal of the REA by certain parties was raised in September. And we will point out with the Ontario Ministry of the Environment, taking over 29 months to comprehensively review and approve our application, we’re confident in the outcome of this review process which is expected to conclude in March of next year. Engineering and procurement of long lead equipment has commenced with the commercial operation of the facility expected in mid-2017. Final permitting approvals for our 177 megawatt wind project located near Chaplin, Saskatchewan, right now are expected to be secured in the next couple of months. Switching to our regulated distribution business group, applications have now been filed seeking a total of more than $30 million in revenue increases in California, Arizona, Massachusetts, and Georgia; and we expect final decisions on these six rate proceedings within the next 12 or so months. With respect to the acquisition of our Park Water company, our water utility located in California and Montana, a settlement agreement regarding approval from the California Public Utilities Commission was reached earlier this year and an order approving the transaction is expected before year end. In Montana, the hearing before the Public Service Commission is scheduled for early January of 2016, and consequently we expect a complete the transaction following the receipt of all approvals early next year. Lastly, with respect to the transmission business group, permitting work is continuing on the $3.3 billion Northeast energy direct natural gas pipeline in which we have an up to 10% interest. In July, we were pleased that Kinder Morgan announced that its Board of Directors had approved proceeding with the project subject to receiving all applicable permits. The environmental review was filed with FERC in June, and filing of the formal FERC certificate application is planned for later this year. Construction is expected to begin in January 2017, with commercial operation targeted for November 2018. The transmission business group development opportunities, with respect to those, we are continuing to expand our presence in the liquefied natural gas business in New England. In addition to the existing facility, which we have under development to serve LDC peak shaving needs, the transmission business group is working with Kinder Morgan to meet additional power generation natural gas loads in the Northeast which were the subject of a recent open season conducted by Kinder Morgan. I would note that several New England states are moving forward with regulatory initiatives to support the pass through, if you will, by electric utilities of long-term gas supply capacity costs, which will obviously help support further infrastructure development. And lastly, our transmission business group is working hard on expanding its pipeline footprint further upstream into New York and Pennsylvania. And while these tidbits and other development opportunities set might seem like teasers, it’s only because they are. For the full story on our growth pipeline, which is approaching $4 billion over the next 4 to 5 years, we would invite you to attend our investor morning being held on December 1st here in Toronto. Details are available on our website or please give Amanda Dillon of our investor relations group a call if you want to hear more about it. And lastly, before we go to questions, I’d like to offer a couple of comments about valuation and perhaps the noted change you would see in terms of our dividend. We believe that our dividend current — our current dividend deal is not fully reflective of the fundamental value of our business. In particular we speculate that perhaps the full Canadian dollar value of our dividend and its growth has not been fully appreciated by the market. Consequently we’ve taken the step of providing our shareholders clarity in terms of Canadian dollar dividend, which is available to our shareholders and in this quarter it is more than $0.125 Canadian dollars. And we hope that this certainty in value helps Canadian investors fully appreciate the compelling investment proposition which we believe that Algonquin provides. So with that, operator, I would like to open it up for the question-and-answer session. Thanks. Operator? Question-and-Answer Session Operator Thank you. [Operator Instructions] Okay. Now, we’ll take the first question from Nelson from RBC Capital Markets. Please, go ahead. Nelson Ng Great. Thanks, good morning everyone. Ian Robertson Great. How you are doing? David Bronicheski Good morning, Nelson. Nelson Ng Quick question on the utility division. I think there was like a large increase in other revenues. I think the disclosure indicates that it was contracted services. Can you provide a bit more color as to like whether this is a like recurring item, or did something one-off take place in Q3? Ian Robertson Sure, Nelson. It is most definitely recurring revenue. I think David had mentioned in his remarks that for services that we provide to let’s call it U.S. government owned facilities you can’t provide — even if we are the utility of record, you don’t get to provide them under the normal state supervised paradigm of regulated tariffs. You provide them under contract. It so happened in this quarter because it’s the summer we obviously did a lot of work on — in one of our facilities that we supply that. But it is ongoing revenue, it just so happens that this quarter happened to be a big quarter because of the summer. But if it is definitely recurring, we are the continuing utility service provider to these bases, and so that’s really the short answer. Nelson Ng I see. So going forward you would see continuing other revenue but generally it’s larger during the summer? Ian Robertson Oh, yes. Of course, I mean, most of the time obviously we do a lot of work during the summer, but yes, it’s just part of the ongoing business, Nelson. Nelson Ng Okay. And then, maybe we could take this offline, but what drove the reduction in interest expense on the renewable division? I think it was down year-over-year and also down relative to Q2, but I think the debt has been I guess flat or higher. David Bronicheski Yes, no. It’s primarily driven by capitalized interest. So we’ve got a number of projects that are under way, and so that’s been I would say the largest driver of that. In addition to that, we retired the LIPSCO bonds, and the LIPSCO bonds, and this is an accounting issue, we’re at a premium because it was on the books at the time. Because of the higher interest rate the bonds carried we retired it, and so that premium went through as is required under GAAP, the interest expense line. I think that was about $1 million I think. But the balance of that was largely just the fact that we’ve got such an extensive capital program that we have higher capitalized interest. Nelson Ng All right. Thanks. I will get back in the queue. Ian Robertson Thanks, Nelson. Operator Thank you. We will now take the following question from Rupert Merer from National Bank. Please, go ahead. Rupert Merer Thanks very much. Good morning, everyone. Ian Robertson Hey, Rupert. Rupert Merer Great quarter. Just a follow up with respect to the contracted services revenues. I see that we’ve had other revenues on that line in the past, but it does seem like quite a large step change. And I understand there’s some seasonality here, but I think if we went back last year it may not have been quite so large. So just wondering has there been any changes in the business that would see a higher sustainable rate in contracted services in the future? Or should we be looking more at a long-term average there? Ian Robertson Well, two things. Let’s point out that it’s the fourth good quarter in a row, Rupert. I didn’t want to cutback. Anyway, in terms of those contracted services, obviously as you can imagine that as projects arise over the course of pipes wear out, things need to be replaced, you just happen to be seeing that in this — with this customer because it happens to be called out on a separate line item. So yes, this quarter did represent — there’s a lot of work that was being done on the bases this quarter, and so it just so happens that they happen to have — should have aggregated together and shown up in the quarter. But as I point out, it’s really very normal course utility operations for us. And while there will be big quarters and low quarters, and as you pointed out last year we didn’t have as big a quarter, this year it happened — there happened to be a lot of projects that needed to be done and it just so happened to have generated substantial earnings. But the business is continuing on, so it’s probably not unreasonable if you want to think about this from your perspective, that there’s just a long-term average that would come out of this and this just happened to be a big quarter. Much as in the way we have other big quarters in other parts of our utility business, it just gets mapped and you don’t see it as — with the clarity because of the accounting treatment. Rupert Merer Okay. Great. And then quickly, you mentioned El Nino and there’s a broad expectation for warm weather in North America. And that could impact your power assets, but looking at the regulated utility business, can you remind us of the sensitivity to the weather and how much decoupling you have right now in your utilities business earnings? Ian Robertson It’s pretty broad based, our decoupling. I would actually flip it around and say their New Hampshire is probably one of the primary jurisdictions where we don’t have sort of solid decoupling from weather phenomenon. So, but in most other states the decoupling mechanisms are pretty effective. Meaning we are pretty insulated from the weather impacts. Rupert Merer What percentage of the … Ian Robertson Sorry, Rupert. Rupert Merer Sorry. What percentage of your earnings you think would be decoupled today? Ian Robertson Well over two-thirds. Well, and I’m speaking just of the utility business, obviously. Rupert Merer Right, yes. Okay, very good. Thanks very much. David Bronicheski And Rupert, I will add, and this will sound like an advertisement for our investor day again, but at our investor day we always provide an annual update on the progress that we’re making in all of our jurisdictions with respect to decoupling and other mechanisms. So we will definitely be providing a full update at our upcoming investor day. Rupert Merer Great. Thank you. Ian Robertson Thanks, Rupert. Operator [Operator Instructions] We will now take the next question from Sean Steuart from TD Securities. Please, go ahead. Sean Steuart Thanks. Good morning, everyone. David Bronicheski Hi, Sean. Sean Steuart Question on the discussions with the Emera with respect to the ownership cap. Has there been any progress there? Any update you can provide for us. Ian Robertson Yes, I will say that the discussions are ongoing. You can imagine we are probably not getting 100% of their attention right now that — with their TECO transaction going through. But as recently as this week, I sat down with Chris Huskilson and — there continues to be strong commitment certainly from the Emera side to their interest, enthusiasm, and excitement for their investment in Algonquin. The work on the strategic investment agreement, I think Chris Huskilson certainly shares my perspective that there are some synergistic opportunities that we can work on together to enhance shareholder value. So I guess I would just say, Sean, that — and I know people have asked the question because of the transformative work that Emera has done with TECO whether there is continued interest. I’d say from our perspective, the relationship feels as strong as it has ever been. Sean Steuart Okay. Thanks for that detail. And just follow up on Mountain Water. Just want to make sure I’m understanding the timing of the appeal for the condemnation, and I guess what happens between now and then and how this feeds into your closing time frame for that acquisition. Ian Robertson Sure. Let me start by saying the whole condemnation process is proceeding in parallel with and really unconnected to the regulatory approval process. Except that I will say that the noise from the condemnation definitely has spilled over to occasion some delays in the Montana Public Service Commission’s approval. The current hearing in that with the Montana PSC is scheduled to believe to start I believe January 16, if I’m not mistaken. And so that’s the regulatory approval process for which we’ve been working with MPSC on. And to be frank, it feels very normal of course for us. In parallel with this has been the whole city of Missoula’s aspirations to own the mountain water system. And that’s been a parallel process in terms of a right to take hearing, which as you accurately point out is under appeal in Montana. But in addition, there is a valuation proceeding, because the next step in a normal condemnation or appropriate expropriation as we would call it here in Canada, is the valuation process. And that’s being held by an independent board of three commissioners who are examining evidence from both sides as to the value of the utility. And their hearing is, if not concluded expects to conclude in the next couple of days with a decision from them probably before year end. And to be frank, if either party doesn’t like the outcome of that decision, there is an opportunity to pursue a jury trial. But I will say that whole condemnation process is independent and unrelated to our acquisition to be frank, when the MPSC completes their work and presumably grants us approval, we will complete and close the transaction; obviously the condemnation will continue on. But that is an under — an ongoing process that anybody who happens to own utilities, and particularly water utilities, which are coveted by the cities that they own, are always open to the condemnation proceedings. And so I will say, Sean, that whole process, you really need to separate the two. And if you’re focused on when we would see the utility join the Liberty Utilities family, it’s really tied to the MPSC hearing. I’m sorry for going on for so long with the answer, but I hope that was — added some more color. Sean Steuart No, that’s great. I appreciate it. Thanks, Ian. That’s all I had. Ian Robertson No worries, Sean. Operator Thank you. We’ll now take the next question from Ben Pham from BMO. Please, go ahead. Ben Pham Okay. Thank you. I wanted to go back to other revenue and then just dig inside a little bit more. And I’m wondering, are you providing — you said utility services to government customers. Is that you’re providing electricity and water? And why is it — why are you characterizing it as contracted? Is it some sort of contract you have in place for a set period of time? Ian Robertson No, well, yes and no, Ben. You can imagine that if a U.S. military base needs water, natural gas service, they don’t obtain those services in the same way as we provide those services under what’s called CC&N, or certificate of convenience and necessity, the way we would do in a normal community and so that you become the provider of those services under extremely long-term contracts. Like 50-year contracts. And so it just so happens that the provision of services to the U.S. government for their bases isn’t provided in a way that from an accounting point of view that it gets lumped in with all of the rest of our utility revenues and utility earnings. It happens to get called out as contracted services because we are the utility provider to that facility, or facilities which are quite large, via contract rather than via a tariff, which is issued and approved by the local state Public Utilities Commission. So it really is the exact same services that we would provide to a customer in Columbus, Ohio or Columbus, Georgia that we might provide to an Army base located in Columbus. Or an Air Force Base located in Goodyear, Arizona versus the customers that we would serve in Goodyear, Arizona. So it really is the exact same business, Ben, and I guess it happens to be step to standing out because this quarter happened to be a big quarter for us in providing services because there were lots of projects that were being undertaken in — on those bases in the summer. And as Rupert had pointed out earlier, yes, it’s a big seasonal quarter. Obviously you do a lot of your construction in the summer, but on an absolute basis it happens to be a big volume just because there was some pent-up demand over the past few years for work that needed to get done. But I would offer up that those revenues shouldn’t — should be thought of as ongoing and consistent recurring revenues, perhaps not in the exact same quantum that they happen to be there, but in the same way as we have yins and yangs in our — in the rest of our utility business across all of our service territories. This just happens to be as I said standout because of the accounting treatment that it receives. Ben Pham Okay. Are you earning the same returns on that? Ian Robertson Yes, we are, sir. Ben Pham Okay. All right. And lastly on Amherst Island, I’m wondering are you — it seems like you are moving ahead with getting the groundwork started before ERT. Is that the plan? Are you going to put a bit of capital before? Ian Robertson Sure. I think we’re highly confident in the outcome of the ERT, as I sort of mentioned in my opening remarks. Gosh, the Ministry of the Environment took 29 months to review and approve our renewable energy application. And to be frank, as you know, the ERT is really a review of the government’s work in terms of the review of the application. And we are highly confident that the government left no stone unturned in terms of their review. And so it makes common sense given that I will say time is money when it comes to projects like this, that we should move ahead on some of the long lead time items. Obviously, we’re doing it prudently, but it certainly represents I think our confidence in the outcome of the process. Ben Pham Okay, got it. Thanks, guys. Ian Robertson Thanks, Ben. David Bronicheski Thanks Ben. Operator [Operator Instructions] We will now take the following question from Paul Lechem from CIBC. Please, go ahead, sir. Paul Lechem Thank you. Good morning. Ian Robertson Hey, Paul. Paul Lechem Good morning. Just a couple of questions around the wind projects under construction, Odell and Deerfield. And you have 50% ownership in those. Just wondering what the terms are to acquire the other 50%? What your decision factors will be, whether you exercise the option or not. And why was it set up this way? Ian Robertson Well, I think in both cases, both Deerfield and Odell, our partners in those projects represent the original developers of those projects. And so clearly you can imagine the community relations, the relations with the — on the permitting point of view they made ideal partners for us in terms of becoming 50/50 partners. I think though having said that, it’s probably totally reasonable to understand that nobody goes into a partnership without a way to exit it. And so there are exit provisions for certainly for up to a buyout in the case of Odell and Deerfield, our 50/50 partners. But that’s certainly not going to happen until the projects get into commercial operation. And we will make the decision at the time as to what makes sense as we look going forward. But we are certainly thrilled to have those guys having a continuing interest. In my mind it’s certainly represents their commitment and belief in the value of those projects. And so what the future holds, don’t really know, Paul, whether we’re going to continue to be 50/50 owners or ultimately buy out our partners and those, which we certainly have the right to do. We will make that decision at the time. Paul Lechem Does the purchase price option — is it at a premium to the original investment or to reflect the de-risking through construction, or is at the same price? Ian Robertson Same price. Paul Lechem Got you. Just on the Ontario market, what’s your level of interest in participating in potential consolidation of the LDCs in Ontario? What would be your competitive positioning in that market if you were to do so? Ian Robertson Well, we obviously have a high interest in expanding our regulated distribution utility business. We would certainly like to participate in the consolidation of electric LDCs. As you know, it’s been a complicated process over the past number of years, largely occasioned by some structures that have been implemented by the government. In some respects I might argue to prevent commercial consolidation to the extent that with the — with Hydro 1 becoming a public entity, maybe the landscape is changing a little. I think our competitive advantages are a cost of capital which is as competitive as anyone from our perspective in the business, but perhaps as importantly a core competency in running regulated utilities. I think I’m very proud with the organization’s track record of providing cost-effective reliable service in all the utilities we provide and man, wouldn’t we love to do it in our own backyard. So I guess from my perspective, Paul, we’re sitting here watching this landscape unfold, but we are cautiously optimistic with the changes from Hydro 1’s perspective that maybe there are some changes afoot and maybe there would be some opportunities for us to participate. So I don’t know if that’s responsive to question. Paul Lechem One follow up on that. Have you actually initiated discussions within any municipalities? Ian Robertson Yes, we certainly have a list and we certainly have had some dialogues with them. Obviously I don’t think it’s appropriate that I disclose with whom with everyone which we’ve spoken, but we have been active in the process, let’s put it that way. Paul Lechem Okay, thank you. Ian Robertson Thanks, Paul. Operator We’ll now take the following question from Nelson Ng from RBC Capital Markets. Please, go ahead. Nelson Ng Great. Thanks. I just want to ask about Bakersfield 1. Could you elaborate on the equipment malfunction and the damage to the inverters? And is it covered — I presume it’s covered by insurance, and do you have business interruption insurance or would you get the missed revenues back some time in the future? Ian Robertson Well, I’ll answer very shortly, Nelson, yes, yes, and yes. But I’ll give you a little bit more color on that. The damage to the inverters occurred during an extremely high volume rain event, and it resulted from the ingestion of moisture into the forced air ventilation system in 3 of the 10 inverter houses. And so the inverters, as you can appreciate, don’t mix well with water. The replacement inverters are on-site and being commissioned as we speak. The repair costs are certainly covered under the original EPC contract. In fact, since final completion actually hasn’t been achieved, even though a substantial completion is there for commercial operations was, this remains the work of the original EPC contractor, and so we’re confident of that. Yes, in terms of business interruption insurance and it’s a 30-day waiting period. To be frank, you can imagine there’s a little bit of complexity with the original contractor as to who is responsible. Is it our insurance company or is it the original contractor to whom we can seek recourse for the lost revenue which is measured in the order of probably $150,000 a month, and so it’s real money. And but that’s the only reason we haven’t made the claim so far, because we’re still trying to sort out all of the contractual liabilities of the various parties. But we’re obviously comfortable that we’ll have recourse ultimately to our insurance company. I think the hope is that within weeks perhaps by the end of this month the plant will be restored to service, and so any lost revenue with respect to it will cease. Nelson Ng I see. Is there any risk of a design flaw for the ventilation system if it got wet because it was raining a lot? Ian Robertson Clearly, there are design changes being made to prevent a recurrence of that water ingestion. I mean the rain event, while being severe; it wasn’t like a tidal wave came from the coast all the way inland to Bakersfield. So clearly the contractor has made design changes, Nelson. And so we’re confident that we actually won’t have a repeat of this. Nelson Ng Okay. That’s good to hear. And then just one last question on the Deerfield wind project. Are you able to comment what level the PPA was set at and how that compares to Odell? Ian Robertson I don’t want to get into the specific numbers of the PPA because you can imagine obviously all the utilities are sort of sensitive to the specific quantum of the rates that are being paid. I think it is fair to say that both of the PPAs were awarded under a competitive process by the respective utilities. I will say that Deerfield enjoys a higher rate than Odell, just for whatever reason. We actually weren’t involved in the bidding of it, but the rate is higher at Deerfield than it is at Odell. But I think really from our perspective as we look at the those projects and we looked at our returns accretion from an earnings perspective, accretion from a cash flow perspective, and from an overall project value on an elaborate after tax IRR perspective, we are a little bit in different maybe agnostic as to the PPA rate as long as the projects meet all of those value accretion criteria which I’m pleased to say that both Deerfield and Odell handily meet. So they’re both solidly in our strike zone from a return perspective, sort of almost notwithstanding the fact that the PPA rates are slightly different. And that’s obviously affecting the total capital cost for the projects are different building in Michigan is different than building in Minnesota. But all in all, they’re both great projects from our perspective. David Bronicheski And Nelson, one other thing in case you may have missed it, as we normally do with projects and acquisitions we have posted a fact sheet on our website, and I’m happy to send it to you if you happen to have missed it. Nelson Ng And I read it and I was thinking like my rough guess was maybe $40, but I just wanted to check in terms of per megawatt hour, but if you don’t want to say it’s fine. Ian Robertson I’m going to be silent right now, Nelson. Nelson Ng All right. That’s great. Thanks again. Okay. Have a good one. Ian Robertson All right, thank you. Operator We’ll now take the following question from Jeremy Rosenfield. Please, go ahead. Jeremy Rosenfield And your silence speaks volumes. I’d like — just keeping on Deerfield, maybe you can provide a little bit of detail on the financing plan? I know looking at the tax equity and other sources of financing, can you just comment in terms of where you see that coming in and what the market is like for ongoing financings for this type of project? David Bronicheski Sure. I’m happy to take that. The financing for Deerfield would be very much the same as the plan that we have for Odell. I think half the project on a long-term basis is going to be financed from tax equity, and those discussions are ongoing. And I think the market is pretty deep for that in the US so we have full confidence of being able to get that. And then as we go through construction, the construction will be financed at a non-recourse basis through a club of lenders in the U.S. It will have the back leverage option for that as well, which the project can slide into for the leverage on the back part of it. And depending on whether we opt to purchase the other 50% or not, and if we do take it onto our balance sheet, then in that instance there’s every opportunity to simply finance the debt portion off our bond platform that we have. Jeremy Rosenfield Okay. Great. Let me just turn to Energy North. There was a comment in the results about potential system expansions in New England. Can you talk a little bit about what the size of that investment might be potentially? Ian Robertson Sure. It’s a bit of a longer answer, Jeremy, because it actually relates to our ability to maximize the synergies between our transmission business group, which as you know is involved in the development of the Northeast Energy Direct a pipeline which runs from right New York, through Massachusetts, up into New Hampshire, back down into Massachusetts at Dracut. Well, you can imagine that pipeline is running through some fairly virgin territory, and I mean virgin, virgin in the context of its service with natural gas. They don’t call New Hampshire the granite state for nothing. It’s very expensive to run pipelines. And so consequently, the installation of the Northeast Energy Direct is going to occasion substantial opportunities for towns to avail themselves of natural gas service to get off of heating oil as a primary heating fuel. We want to obviously support and encourage that conversion. We have filed a number of regulatory — opened a number of regulatory proceedings applying to be the utility of record for towns that we believe can be economically served by the proximity of the Northeast Energy Direct pipeline. And so the size of that opportunity could be material. We estimate that there is up to 30,000 new customers that could be served along the course of that pipeline in southern New Hampshire. And so it’s going to be substantial. I will point out that we are planning to give a lot more detail, Jeremy, at our investor morning. And so as I said, a shameless plug for our investor morning; I hope you make the trip up here from Montreal. But certainly it is part of the material expansion thesis for our presence of — in the New England natural gas marketplace. I don’t know if that gives you some comfort or some color. Jeremy Rosenfield I was kind of looking for sort of a dollar investment amount, but I guess I’ll have to make the trip up to find the correct answer there. Ian Robertson There you go. Jeremy Rosenfield I appreciate it. Those are my questions. Thanks. Ian Robertson Thanks, Jeremy. Operator [Operator Instructions] There are no further questions. Please continue. Ian Robertson Great. Thanks, everyone. Appreciate you taking the time on our Q3 2015 conference call. And obviously, as always, I ask you to remain on the line for a riveting review of our disclaimer by Amanda Dillon. Amanda? Amanda Dillon Thank you, Ian. Certain written and oral statements contained in this call are forward-looking within the meaning of certain securities laws and reflect the views of Algonquin Power and Utilities Corp with respect to future events based upon assumptions relating to among others the performance of the Company’s assets and the business, financial, and regulatory climates in which it operates. These forward-looking statements include, among others, statements with respect to the expected performance of the Company, its future plans, and its dividends to shareholders. Since forward-looking statements relate to future events and conditions, by their very nature they require us to make assumptions and involve inherent risks and uncertainties. We caution that although we believe our assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that our actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include those presented in the Company’s most recent annual financial results, the annual information form, and most recently quarterly Management’s discussion and analysis. Given these risks, undue reliance should not be placed on these forward-looking statements. In addition, such statements are made based on information available and expectations as of the date of this call and such expectations may change after this date. APUC reviews materials forward-looking information it has presented not less frequently than on a quarterly basis. APUC is not obligated nor does it intend to update or revise any forward-looking statements whether as a result of new information, future developments, or otherwise, except as required by law. With respect to non-GAAP financial measures, the terms adjusted net earnings, adjusted earnings before interest, taxes, depreciation, and amortization, adjusted EBITDA, adjusted funds from operations, per share cash provided by adjusted funds from operations, per share cash provided by operating activities, net energy sales, and net utility sales, collectively the financial measures, are used on this call and throughout the Company’s financial disclosures. The financial measures are not recognized measures under generally accepted accounting principles, or GAAP. There is no standardized measure of these financial measures. Consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of the financial measures and a description of the use of non-GAAP financial measures can be found in the most recently published Management’s discussion and analysis available on the Company’s website and on SEDAR. Per share cash provided by operating activities is not a substitute measure of performance for earnings per share. Amounts represented by per share cash provided by operating activities do not represent amounts available for distribution to shareholders and should be considered, in light of various charges and claims, against APUC. Thank you for your time today. Operator Ladies and gentlemen, this concludes the conference call for today. We thank you for your participation. You may now disconnect your lines and have a great day.