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Gas Natural’s (EGAS) CEO Gregory Osborne on Q4 2015 Results – Earnings Call Transcript

Gas Natural, Inc. (NYSEMKT: EGAS ) Q4 2015 Earnings Conference Call March 16, 2016, 16:30 ET Executives Deborah Pawlowski – IR Gregory Osborne – President & CEO Jim Sprague – VP & CFO Kevin Degenstein – COO & Chief Compliance Officer Vince Parisi – General Counsel Analysts Jay Dobson – Wunderlich Securities Operator Welcome to Gas Natural Incorporated Fourth Quarter and Full Year 2015 Financial Results Conference Call. [Operator Instructions]. I would now like to turn the conference over to your host Ms. Deb Pawlowski. Thank you, Ms. Pawlowski. You may begin. Deborah Pawlowski Thanks, Chris, and good afternoon everyone. Welcome to our 2015 fourth quarter and full year earnings teleconference call. Joining me on the call today are Gregory Osborne, our President and Chief Executive Officer; Jim Sprague, Vice President and Chief Financial Officer; Kevin Degenstein, our Chief Operating Officer and Chief Compliance Officer as well as Vince Parisi, our General Counsel. Gregory and Jim are going to review the quarter and year and also give an update on our outlook and strategic progress and then we will open it for question-and-answer session. You should have a copy of the financial results were released yesterday after market closed and if not you can access, it’s on our company’s website at www.egas.net. As you’re aware, we may make some forward-looking statements on this call during the formal discussion as well as during the Q&A. These statements apply to future events that are subject to risks and uncertainties as well as other factors that could cause actual results to differ materially from what is stated on today’s call. These risks and uncertainties and other factors are provided in the earnings release as well as with other documents filed by the company with the Securities and Exchange Commission. These documents can be found on the company’s website or at sec.gov. So with that, let me turn it over to you Gregory to begin. Gregory? Gregory Osborne Thank you, Deb and good afternoon everyone. I appreciate your time today ad your interest in Gas Natural. While our financial results for the fourth quarter of 2015 do not demonstrate the advances we have made we have in fact made measurable progress. First we completed the sale of a Kentucky and Pennsylvania utilities and our former corporate offices combined with the sale of our Wyoming assets last summer we had a total realization of nearly 20 million in cash from our asset rationalization program in 2015. By even sold these utility assets we can focus our energies and resources on North Carolina and Maine which have higher growth potential while leveraging our scale in Montana and Ohio and factor in the fourth quarter we added approximately a thousand customers. For 2015 we have added a total of 2000 new customers for the full year practically offsetting reduction in customers from the sales Pennsylvania and Kentucky. Secondly, we launched the final phase of our enterprise resource planning or ERP System implementation during the quarter. The system is both costly and challenging to implement but we believe it is necessary to support our growth strategy and facilitate operational efficiency and consistency. Most recently on February 18th we announced a proposal to form a new organizational structure. Subject to regulatory approval that will align our eight regulated utility operation under one fully owned subsidiary further segregating our regulated entities from our non-regulated operations. We believe the structural streamline regulatory processes and create efficiencies with our four regulatory jurisdictions in which we now operate. This two corporate structure will also simplify our financing arrangements and enhance our financial flexibility. In conjunction with this proposal we reached agreement with our lenders to refinance and reconsolidate our debt at the parent company level. The new $99 million debt facilities will replace our existing debt agreements and provide more balance to our capital structure, placing us closer to a 50:50 debt to equity ratio. We also expect the new credit arrangement will provide us much greater flexibility. We have made some new proposed new organizational structure and debt agreements to the appropriate regulatory authorities and anticipate that the review and approval process will be completed in the second half of 2016. Also on the regulatory front most of you know the stipulation or recommendation between the Ohio utilities and our commission staff or the PUCO was filed on October 30th with the commission. The stipulation was related to the 2014 investigative audit of our Ohio utilities because all stipulations are subject to review and final approval by the commission, our recommendation with the staff is still subject to PUCO approval. Turning to our financial results for the quarter, like many natural gas utilities our revenue and gross margin were virtually affected by much warmer than normal weather in 2015. Well typically our geographic diversity works in our favor this year the warmer weather was across all markets we serve. Looking ahead we’ll be evaluating decoupling mechanisms in all of our jurisdictions to reduce the impact of unfavorable weather conditions on our financial performance. During the quarter our operating income was also unfavorably impacted by costs associated with their ERP system implementation. I’ll now turn it over to Jim to more fully review the details. Jim? Jim Sprague Thank you, Gregory and good afternoon everyone. Thank you for joining us today. Our fourth quarter 2015 financial results reflect lower full service distribution throughput primarily due to warmer weather in all of our markets as Gregory managed. Because of a typical expense items that impacted our results for the quarter and year we present both GAAP and adjusted non-GAAP results. Consolidated revenues decreased to 29.5 million down 7.5 million on an 11% decline in full service distribution throughput. I’m going to focus my review on the contributing factors of our results on the natural gas operation segment which currently makes up 90% of our revenue. Revenue from our natural gas operations decreased 8.2 million or 24% to 26.6 million. The primary drivers of the decline were warmer weather and lower gas prices passed on to customers in all of our markets as well as impact of the disposition of our Pennsylvania and Kentucky utilities. Consolidated gross margin was 12.3 million in the quarter almost $300,000 higher than the 2014 fourth quarter. In the natural gas operations segment, gross margin was 12.1 million, an improvement of 227,000 over 2014. 2014 was penalized by an unfavorable GCR adjustment. The gross margin for the 2015 fourth quarter was negatively impacted by lower throughput which was a direct result of an 11% decline in [indiscernible]. Consolidated operating expenses for the fourth quarter of 10.1 million increased by 1.2 million compared with the prior year quarter. 1 million of the increase was related to our ERP System. As Gregory noted we believe the investment in our ERP system is needed to establish the foundational structure to support our future growth. Considering the decline in gross margin from lower throughput and higher operating expense income from continuing operations for the quarter was 700,000 or $0.07 per share down from 1.2 million or $0.11 per share in 2014 fourth quarter. Adjusted EBITDA from continuing operations, a non-GAAP number was 3.8 million compared with 6.5 million in the 2014 fourth quarter. You can find the reconciliation of GAAP to non-GAAP numbers in the news release where we quantified a typical legal and regulatory cost as well as other atypical items. Turning to the full year of 2015 9% lower throughput drove the declines in consolidated revenue to 112.4 million, 20.2 million lower than 2014. Revenue from our natural gas segment declined by 19.1 million or 16% to 104 million with the change largely driven by the same factors as the quarter with warmer weather having the largest impact in the Ohio, Montana and North Carolina market and also a 500,000 reduction in the second quarter for adjustments to sales volumes used in the unbilled revenue calculation. On the positive side we had a 1.8 million volume related increase from customer growth in May including revenue from the Loring pipeline which began service in the September 2014. Gross margin in the natural gas operations segment for the full year decreased by approximately 400,000 to 43.6 million from lower weather related sales volumes. PUCO gas cost adjustments in Ohio, volume adjustments to the unbilled revenue calculation in North Carolina and the impact of the disposed utility. We were able to offset some of these cost increases with the incremental gross margin generated from the startup of a Loring pipeline and more favorable pricing in May. The same factors in the quarter where the primary contributors to a 1.5 million or 4% increase in operating expenses for the year. Income from continuing operations was 1.2 million or $0.11 per share down from 2.7 million or $0.26 per share in 2014. Adjusted EBITDA from continuing operations was 16.4 million down 2.7 million compared with 2014. As I noted earlier please refer to the reconciliations for non-GAAP measures in the press release. Turning to the balance sheet, we had 2.7 million of cash at December 31, 2015 up from 1.6 million at year-end 2014. As Gregory indicated we expect that our proposed reorganization of the company and the related refinancing of our long term debt which does not come due until mid-2017 will provide us with greater financial flexibility. Both are subject to regulatory review and approval. With letter approval secured and our legal and regulatory filings submitted in February this process is well underway and we expect completion in the second half of 2016. Cash provided by operating activities of continuing operations was 9.4 million in 2015 down from 11.1 million in 2014 on lower income. Capital expenditures for 2015 were 9.6 million down measurably from 21.6 in 2014. Investment in 2015 were focused on adding services to install Main that will support customer expansion primarily in our growth market. At this time we have budgeted 4.7 million of investment for 2015. The refinancing coupled with the timing of decline of atypical expenses will determine how much additional cash we will direct to capital expenditures. We are confident that the improvements we have made over the last year and our project selection and management processes will focus our investments and resources in those areas with the highest potential ROI. With that summary let me turn the call back to Gregory. Gregory? Gregory Osborne Thank you, Jim. I would like to take a moment to articulate our strategy which is to number one normalize relations with our regulatory bodies. Number two, rationalize our assets and focus on our core strengths. Number three, internally unify our operations and sell a single operating platform and install a comprehensive set of internal controls and procedures to be followed throughout the entire organization. Number four, undergo a recapitalization of our debt structure at the parent company level with favorable terms for all entities under the corporate umbrella. Number five, reorganize the corporate structure to simplify the command and control functions, provide clarity to our regulators as well as our other stakeholders. Number six, realize efficiencies within each of our operating units through shared services and number seven identify and execute acquisition opportunities that can be assimilated into the reconstructed operations. Underline these initiatives our continued organic growth opportunities within each of our operating units. The strategy also recognizes there are legal matters getting resolution in amidst of our other achievements and we are diligently working to resolve them as expeditiously as possible, but they do take longer than we like. While there’s still work ahead of us we look forward to concentrating our resources and energies in those areas of our business with the best prospects for growth and increased earnings power. And now let’s open the line up for questions. Question-and-Answer Session Operator [Operator Instructions]. And our first question comes from the line of Jay Dobson with Wunderlich Securities. Please proceed with your question, sir. Jay Dobson Jim, help me wrap my head around what would be the sort of weather I guess on I guess earnings but it might be easier to do it on gross margin for the fourth quarter and 2015 and I guess I’m looking at that sort of versus normal I know that’s a bit of a science project but just trying to get at sort of you know the earnings or earnings power of the entity as it stands now. Jim Sprague Well Jay as you see the relationship between then [indiscernible] degree days and throughput you see a real correlation there. Our margins were impacted — the heat degree days were roughly 11% lower than the weighted average from all our jurisdiction and that corresponding throughput was decreased by that as well by a similar percentage. So when you look at that you’re going to see that there is impact that would — and obviously our base rates are different by each jurisdiction. So to give you a specific number we would require some level of computation you know going back to each of our jurisdictions. But it is somewhat proportional that when you look at those divergence from normal you see a proportional in fact to our gross margin. Jay Dobson I absolutely appreciate that, I’m trying to get at sort of what the earnings or earnings power is of the entity on a more whether normal basis because as Greg pointed out you know the results clearly don’t reflect in the fourth quarter for the full year sort of the progress you all have made on sort of restructuring the entity, maybe then turning to costs you know sort of away from the legal and regulatory cost that are probably or certainly are going to be sort of coming down. What do you see is the overall trajectory for costs in 2016? Jim Sprague Well when we put together our budget for 2016 we had in mind several initiatives we were looking to certainly make sure that customers safety and reliability in the system was maintained as well as exceptional customer service. So with that in mind we charged each of our general managers to review their current cost structure and identify areas where there could be some a efficiencies drawn within each of those jurisdictions. We also did that at the corporate level. We looked at our individual cost and we looked at functional areas and made sure that we were running an efficient operation. As Gregory mentioned and his summary we’re also looking more closely at shared services, one of the — what we see is a big benefit of bringing the ERP system on line is to — now that we’re operating on a uniform platform where there are opportunities for us to share cost and understand that the command and control still needs to be locally at utility level but we’ve also got opportunities from a mechanical standpoint to find ways to draw efficiencies there. So you know again I don’t have a quantified number in front of me to be able to tell you what that is but I will say that we’re going to follow up on a management summit that we have last year again this year to explore more opportunities to find those shared services would like to shoot for a cut of probably 10% to 15% operating expenses at least for the current year and then there is respective of the atypical expenses that we had in relation to some of these ongoing matters particularly as it relates to some of the legal matters that still require some effort on our part to bring to a close. Jay Dobson And I think Gregory on the decoupling you alluded to, you know you and I have talked about sort of rate cases and when those occur. Has the thought process around the next sort of round of rate cases changed at all because I think of decoupling as something you’d have to do in the context of a rate case. So anyway just trying to think of that’s something closer in than a couple years off which is when I was thinking rate cases might occur. Gregory Osborne This has been a big topic of discussion obviously with the weather and it’s been on our minds for the last several years. A number of utilities in Ohio for instance have gone this route. So it’s something that we’re paying attention to and focused on. Vince can you speak a little more into detail in regards to Jay’s question? Vince Parisi Yes, there is certainly something we explore and I think you hit right on head you know typically you’re going to see something like decoupling mechanism coupled with a rate case process. Certainly looking at whether there are opportunities to do it outside that context but typically you’re going to see those two kind of follow along with each other. So I think you’re probably right on with respect to time. Jay Dobson And then one last one just on Ohio, you probably don’t want to stay very much but you know we more waiting and hear any hints of when the PUCO might make some decision? Gregory Osborne We really focused at the beginning of this year really I’m getting to financing applications together and filed, it’s really been quiet on that front which I think is a positive obviously we would like to get that one to full inclusion but at this point we’re just waiting for that stuff [indiscernible]. Operator Our next question comes from the line of [indiscernible]. Please proceed with your question. Unidentified Analyst Glad to hear about the ERP system. The 1.3 million I’m assuming that is a large number that has the sort of onetime costs in that, can you give us a sense of on a per quarter or per year basis what the ERP increase will be on an ongoing basis? Gregory Osborne Yes. Greg, when we had been accumulating cost prior to actually our final days of launch. We had been grouping all of our cost into a category called build to suit asset on the balance sheet and when the system went live we did the deep scrub of those cost and reallocated or expense those items that were not capitalized than would have been related to training cost and some of those other period type cost that would not be eligible to capitalize and when we did do this we set up basically say a leaseback transaction on a capital lease which was — we constructed this asset obviously from the license to the form we had it. So there was a component of that that will be written off over a period of the lease term which is 36 months and that number is — we had a component of that in those expenses this year and then the final component of those additional costs then would be actual depreciation of the system itself which we’re amortizing that over a 10 year period and finally then due to the capital lease treatment as we’re making payments to on the financing, and on the lease payment a portion of that lease payment is going to interest expense. So the period caused that we experienced and included in the fourth quarter was a $1 million and the remaining 300,000 both cost from the 1.3 were interest cost that were associated with that. Now on an ongoing basis for the next three year amortization of that what we call the prepaid rent that’s roughly $700,000 a year, we took three months of that. So there’s 33 more months of that expense and then on an annual basis. The depreciation associated with the SAP system is approximately that’s about another $700,000 that we’re taking over the 10 year period. So, that will be amortized on a straight line method so you’ll see that coming in, the 700 on the prepaid rent will expire at the end of ’18. Unidentified Analyst And so is it fair to say that there are obviously you’re looking at those capitalized costs in the ongoing sort of fixed type costs, but in terms of the people and the sort of the variable cost portion of that, is that — has it been reduced because you’re more efficient there or is that the personnel NOL [ph] like? Gregory Osborne Again Greg as I alluded to with the shared services we see that is going to be easy the largest opportunity for us to recognize some cost reductions within the organization. We went live October 1st, there is — and Kevin who is also on the line with us today has assumed some of those coordinator duties with the ERP system that we’ve launched but we’re looking to bring that to what we call a steady state which is you know working out some of the final issues with report rating and some of the other functionality issues and once those are done we’re going to put together we’ve got an RFP out there for us, an application support maintenance agreement going forward and then as I said the shared services then because we’re going to be operating on a single platform throughout the entire organization will provide us with the ability then to review our systems and find some efficiencies that will allow us then to reduce the functionality cost that we have within our jurisdiction and allow some shared services then to provide that. That will be a good topic of our summit next month. Unidentified Analyst With regard to the approval and the restructuring, you’re under four jurisdictions to get the new structure and the decoupling and all that in place do you have to go to the four jurisdictions and say is this all right, is this structure we’re setting up, is this fine, is that how it works? Or is it — will it come sort of piecemeal as you file for new rate cases? Vince Parisi Really the two items will be separate, we’ve already filed the applications with respect to financing those are ongoing. We’re really in the discovery stage with respect to those and we expect to see some resolution there this year sometime towards the second half of this year. the decoupling mechanism really would be probably a broader rate cases and we’re exploring those opportunities. You know we have had recent rate cases some of our jurisdictions and others there are obvious little bit older so where we have those opportunities will certainly explore those but they will be [Technical Difficulty] line. Unidentified Analyst But do you need for separate approvals in the jurisdictions or is that there’s just one? I don’t quite understand the approval process or what’s needed to be approved? Vince Parisi With respect to the decoupling components or the rate cases those will be state specific. So we will need — part of what we’re doing ultimately is something to get the structure in place as well and the financing application, the idea of being clearly bucketing each of the regulatory jurisdictions with respect to those regulated utility. So we would need for example to get approval or on a higher rate case for example with decoupling in Montana. Unidentified Analyst Okay. And then in the text you mentioned the Loring pipeline and the gross margin was incremental there. Could you talk about the gross margin percentage relative to the Loring pipeline and is that going to be a positive on a percentage basis and how is that going to change over time? Kevin Degenstein Yes I think from a percentage basis I don’t have the numbers directly in front of me but ultimately the Loring pipeline does provide a backbone to the Bangor system. It allows for additional industrial customers and commercial customers as you go to Lincoln and as you said head south out of Bangor it gives us the opportunity to pick up some other industrial customers, some other communities and high school [ph]. So incrementally the percentage that it provides will increase and will be a positive to the Bangor gas system. But for an actual incremental percentage I don’t have that on the top of my head. Operator [Operator Instructions]. Our next question comes from the line of John Bear from Assent Wealth Advisors [ph]. Please proceed with your question. Unidentified Analyst I’ve a question on your throughput volumes during the summer period in idea that if you have hotter than normal summer conditions. Do you supply gas directly to the power generators? Kevin Degenstein No we don’t have a summer time load to the power generator, so we’re not affected by warm weather or electrical demand. We just don’t have any of that market captive. Obviously from our perspective construction, money into roads, asphalt [ph] plans and things like that do provide some summertime load but we do not have a captive generation market. Unidentified Analyst Is that something that you could address and work on you know obviously in the summer time or I mean in the winter time you know you like it real cold but just wondering if that’s a possible another outlet for distribution for you. Kevin Degenstein Yes, I think ultimately the answer to that would be yes, if there was power generation built into the geography we serve or in an area by which we could serve and provide services we’d be more than happy to do that but then again it is going to be in the specific utility of geography specific and we would need to have them built in our service territory to provide by the utility. Unidentified Analyst Are you seeing any opportunities in that area? I mean there seems to be a real gravitational wave from coal fired plants in the northeast. Kevin Degenstein Yes not specifically– Unidentified Analyst Just saying, in Ohio you know shut down First Energy shut down, you know a lot of their coal plants. Kevin Degenstein I agree wholeheartedly with you know, we’re not seeing any at this time. But if they would become available within our territory and the market moves that way which I agree it is we would much prefer to fire with natural gas than coal. We would move into that market once it becomes available and we become aware of it. But right now we do not see anything in the immediate future. Operator There are no further questions in queue at this time and I would like to turn the conference back over to Gregory for any closing comments. Gregory Osborne Thank you, Chris. In closing I’d like to thank you all for joining us this afternoon for a 2015 fourth quarter and full year earnings teleconference. And I also would like to thank all of our employees for dedicated, hard work and commitment to Gas Naturals’ long term success. Finally I’d like to thank our board for their ongoing support and advice. This is an exciting time for Gas Natural as we continue to execute our strategy to establish our business as a benchmark gas utility with greater earnings power. Thank you again for joining us. Have a great evening. Operator Ladies and gentlemen this does conclude today’s teleconference. We thank you for your time and participation. 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Duke Energy: A Safe High-Yield Dividend Stock For Retirement

Duke Energy (NYSE: DUK ) is a favorite high-yield dividend stock for income investors, and it’s no wonder why. The company has paid uninterrupted quarterly dividends for 90 years and is set to increase its dividend for the ninth consecutive year in 2016. Regulated utility companies such as Duke can provide safe retirement income with less risk than other types of businesses because of their predictable earnings, government-supported competitive advantages, and relatively low stock price volatility. For these reasons and more, we own several utility stocks in our Conservative Retirees and Top 20 Dividend Stocks portfolios. However, just because a stock appears to have little fundamental risk does not mean it is a safe investment. The price paid for a stock is still very important, and that is especially true for low-growth utility stocks. While utility companies can be relatively attractive income investments compared to bonds due to their potential for capital appreciation and moderate income growth, it’s still important to diversify a portfolio’s income streams in other sectors. Unexpected shocks can still happen across entire sectors, and no one living off dividends desires to deal with unpleasant, avoidable surprises when it comes to their nest egg. Let’s take a closer look at Duke Energy’s business to see if it’s a stock we should consider for our utilities exposure. Business Overview Duke Energy’s history dates back to the early 1900s, and the company is largest electric utility in the country today with over $23 billion in annual revenue and operations reaching across the Southeast and Midwest regions. Duke Energy is a regulated utility company that serves approximately 7.4 million electric customers and 1.5 million gas customers, including customers from its planned $4.9 billion acquisition of Piedmont Natural Gas (more on this later). Regulated utilities account for about 90% of Duke Energy’s business mix, but the company also has a commercial portfolio of renewables and gas infrastructure (5%) and an international energy business in Central and South America (5%), which it recently put up for sale. The company’s regulated utilities primarily rely on coal (29%), nuclear (27%), and natural gas (23%) for its generation of electricity. Hydro and solar generate another 1% of the company’s total energy, and Duke Energy also purchases about 20% of its power. Click to enlarge Source: Duke Energy Investor Presentation Business Analysis Regulated utility companies are essentially monopolies in the regions they operate in. With the exception of Ohio, all of Duke’s electric utilities operate as sole suppliers within their service territories. Building and operating the power plants, transmission lines, and distribution networks to supply customers with power costs billions of dollars, and it would generally be unprofitable and inefficient to have more than one supplier for a region. State utility commissions also have varying degrees of power over the construction of generating facilities, which further restricts competition. The downside to the “monopoly” enjoyed by regulated utilities is that their services are priced by state commissions. This is done to keep prices fair for consumers and allow utility companies to earn a reasonable, but not excessive, return on their investments to encourage them to provide safe and reliable service. A utility company’s attractiveness is largely driven by the states it operates in. Some have more favorable demographics (e.g. population growth) and regulatory bodies. Duke Energy’s mix is generally favorable. Over the past three years, base rate cases approved to Duke Energy have granted the company a return on equity ranging from 9.8% to 10.5% across the Carolinas, Ohio, and Florida. We think these returns are very reasonable and suggest a generally favorable set of regulatory bodies in Duke’s core operating states. In addition to the industry’s promotion of stability, Duke’s business has undergone a rather significant transformation over the last five years to improve the reliability of its earnings and cash flows. Duke Energy’s biggest move was its acquisition of Progress Energy in mid-2012 for over $13 billion, significantly enhancing the company’s scale and market share in regions such as the Carolinas. Duke Energy has realized over $500 million in cost synergies from the deal and become a more efficient energy provider. The company next entered the regulated pipeline business in 2014 to help its efforts to replace coal power plants with cleaner and cheaper natural gas generation facilities. In October 2015, Duke Energy announced a deal to acquire Piedmont Natural Gas for $4.9 billion to boost its push into gas. Piedmont is a regulated gas distribution company that delivers natural gas to customers in the Carolinas and Tennessee. The company owns valuable gas infrastructure that currently supports Duke’s gas-fired generation in the Carolinas and will be further expanded to help with Duke’s ongoing conversion from coal to gas. Regulated gas companies also offer strong and predictable returns on capital (Piedmont’s return on equity is about 10%) and should continue to benefit as a result of the natural gas surplus in the U.S. Compared to electricity sales, which seem likely to slow as energy usage becomes increasingly efficient, gas has a stronger growth profile (Piedmont has investment pipeline growth of 9%). This is because new pipelines coming on-line will allow gas to replace dirtier power sources such as coal in regions where gas was previously inaccessible. Piedmont will about triple Duke’s number of natural gas customers to approximately 1.5 million and help establish a platform for future growth in gas infrastructure projects. After the deal closes, Duke Energy expects roughly 90% of its assets to earn regulated returns, which should provide very reliable earnings. Duke Energy has also gotten rid of non-strategic assets to lower its risk profile and improve the quality of its earnings. Management sold the company’s merchant Midwest commercial generation business to Dynergy for $2.9 billion in early 2015 and placed its struggling Latin American generation business up for sale in February 2016. Each of these businesses had less predictable earnings and greater macro risk. Duke Energy believes its current business mix is now 100% focused on its core operations, whereas 25% of the company’s 2011 net income was derived from non-core businesses. Management now expects to spend $8 billion on new generation investments, $10 billion on gas & electric infrastructure, and $2 billion on commercial & regulated renewables to drive 4-6% annualized earnings growth over the next five years. Overall, we believe Duke Energy has a strong moat. The company has excellent scale as the largest electric utility in the country and operates primarily in regions with generally favorable demographic trends and regulatory frameworks. Management has simplified Duke’s mix to focus on core regulated businesses that provide reliable earnings and new growth opportunities in natural gas and renewable generation resources. While the utility sector is gradually evolving, we believe Duke Energy is here to stay for a long time to come. Duke Energy’s Key Risks Uncontrollable macro factors such as mild temperatures and industrial activity can impact Duke Energy’s near-term financial results. However, we believe these are transitory issues that have little bearing on the company’s long-term earnings potential. The bigger risks worth monitoring are changes in state regulations, population growth trends in key states, increased environmental regulations, and execution of the company’s business strategy (e.g. large projects and acquisitions). The rates Duke Energy can charge its customers are decided at the state level. Similar to what we observed when we analyzed Southern Company (NYSE: SO ), another regulated utility, most of the regions Duke Energy operates in have generally favorable regulatory environments and are characterized by positive population and economic growth. However, the company is banking on these conditions remaining stable as it continues investing for growth and depending on states to approve rate increases to earn a fair return on its capital-intensive investments. The Environmental Protection Agency (EPA) also creates risk for utility companies in the form of enhanced safety and emissions standards. Duke is still dealing with its notorious coal ash spill that took place in North Carolina in 2014, and the company is gradually shifting its mix of power away from coal in favor of cleaner sources such as natural gas. Finally, over the very long term, electric utility companies will need to deal with the reality that demand is gradually decaying thanks to increasing energy efficiency and distributed generation (e.g. rooftop solar). Duke has earmarked about $2 billion for growth investments on commercial and regulated renewables over the next five years, but it’s still a relatively small proportion of the overall business. The company’s acquisition of Piedmont should also help the company with growth initiatives outside of regulated electric utility services. Dividend Analysis: Duke Energy We analyze 25+ years of dividend data and 10+ years of fundamental data to understand the safety and growth prospects of a dividend. Dividend Safety Score Our Safety Score answers the question, “Is the current dividend payment safe?” We look at factors such as current and historical EPS and FCF payout ratios, debt levels, free cash flow generation, industry cyclicality, ROIC trends, and more. Scores of 50 are average, 75 or higher is very good, and 25 or lower is considered weak. Duke Energy’s Dividend Safety Score of 80 indicates that the company has a very safe dividend payment. Duke’s dividend has consumed 81% of its diluted earnings per share over the last 12 months. A payout ratio this high is usually cause for some concern because it provides less wiggle room in the event of an unexpected drop in profit. However, regulated utility companies are able to safely maintain higher payout ratios because their earnings are (generally) extremely steady, making utilities one of the best stock sectors for dividend income . Using management’s “adjusted” earnings, Duke Energy’s payout ratio is closer to the company’s target range of 65%-70%. As seen below, Duke’s payout ratio has been above 60% each of its last 10 fiscal years. Source: Simply Safe Dividends Not surprisingly, utility companies hold up relatively well during economic recessions. As seen below, Duke Energy’s revenue edged down by just 4% in 2009. While customers use somewhat less electricity during periods of weak growth, they still need it to live. DUK’s stock also fared well in 2008 and outperformed the S&P 500 by 15%. Source: Simply Safe Dividends As we mentioned earlier, regulated utility companies earn very stable earnings. As a state-regulated monopoly company selling non-discretionary services, it’s no surprise to see Duke Energy’s consistent results below. Source: Simply Safe Dividends Duke Energy’s earnings are steady, but regulators control the rates the company can charge customers to ensure pricing is fair. As a result, the returns Duke can earn on its capital projects are capped, and the company’s return on invested capital has remained in the low- to mid-single digits over the last decade. Source: Simply Safe Dividends The capital-intensive nature of utility companies makes them heavily dependent on debt to run and grow their businesses. As seen below, Duke has less than $1 billion in cash on its balance sheet compared to nearly $40 billion of debt. However, the company’s excellent business stability has enabled Duke Energy to maintain an A- credit rating with Standard & Poor’s . While the company’s free cash flow will remain restricted the next few years to fund its major growth investments, forcing it to lean even more on debt markets, we still view Duke as a healthy business as well. Click to enlarge Source: Simply Safe Dividends Overall, the stability of Duke Energy’s earnings and non-discretionary nature of its services significantly boosts the safety of its dividend payment despite its levered balance sheet and relatively high payout ratio. Dividend Growth Score Our Growth Score answers the question, “How fast is the dividend likely to grow?” It considers many of the same fundamental factors as the Safety Score but places more weight on growth-centric metrics like sales and earnings growth and payout ratios. Scores of 50 are average, 75 or higher is very good, and 25 or lower is considered weak. While regulations generally protect utility company’s earnings and market share, they also limit growth opportunities. As a result, most utility businesses have below-average dividend growth rates, and Duke Energy is no exception. The company’s Dividend Growth Score is 20, which suggests that its dividend growth potential is lower than 80% of all other dividend-paying stocks in the market. However, its dividend has been reliable. Duke Energy has made quarterly dividend payments since the 1920s and will raise its dividend for its ninth consecutive year in 2016, keeping it a far distance from joining the dividend aristocrats list but rewarding shareholders nicely. For most of the last 10 years, Duke Energy grew its dividend by an annualized rate of about 2%. However, management expects to double the dividend’s growth rate to 4% per year to better reflect an improvement in Duke’s lower risk business mix and core earnings growth rate of 4%-6% per year. Source: Duke Energy Investor Presentation Higher dividend growth will cause Duke Energy’s earnings payout ratio to increase from its 65%-70% target to closer to 75% in the near term as its growth investments continue, but the payout ratio is expected to turn down over time. Valuation DUK’s stock trades at 16.8x forward earnings estimates and has a dividend yield of 4.2%, which is slightly below its five-year average dividend yield of 4.4%. Since 2009, the company has met its long-term annual adjusted diluted earnings per share growth objective of 4%-6%. Assuming Duke Energy’s growth projects continue helping its core businesses realize 5% annual earnings growth over the coming years, the stock’s total return potential appears to be about 9% per year. Considering the stability of Duke Energy’s earnings, which are largely composed of regulated utility operations, we think the stock is reasonably valued today but not a bargain. Conclusion For investors seeking exposure to utility stocks and safe dividend income, Duke Energy appears to be a reasonably-priced blue chip dividend stock to consider. Almost all of the company’s business mix consists of regulated operations, which provide predictable earnings with low volatility. Most of the regions Duke Energy plays in are also characterized by favorable demographics and historically supportive regulatory bodies. While there is some long-term risk resulting from lower electricity usage trends, the rise of clean renewables, and the company’s major growth investments, we think Duke Energy will remain an appealing income investment for many years to come. Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.

Alterra Power’s (MGMXF) CEO John Carson on Q4 2015 Results – Earnings Call Transcript

Alterra Power Corp ( OTCPK:MGMXF ) Q4 2015 Earnings Conference Call March 16, 2016 11:30 AM ET Executives Ross Beaty – Executive Chairman John Carson – CEO Lynda Freeman – CFO Lindsay Murray – Interim CFO Jay Sutton – Head of Hydro Paul Rapp – Head of Geothermal and Wind Operations Murray Kroeker – Head of Engineering and Solar Jon Schintler – Head Project Finance Analysts Marin Katusa – KCR Fund Steven Hong – National Bank Operator Good morning, ladies and gentlemen and welcome to the Alterra Power Corp Fourth Quarter Results Conference Call. At this time all lines are in a listen-only mode. But following the presentation we will conduct a question-and-answer session. [Operator Instructions] Note that this call is being recorded on Wednesday March 16, 2016. And I would like to turn the conference over to Ross Beaty. Please go ahead sir. Ross Beaty Thank you very much operator and good morning ladies and gentlemen, I’d like to extend my own welcome to you for joining us at Alterra’s fourth quarter and year-end results 2015 conference call. Before I get going, I want to point out that we have a lot, we’ll be making some forward looking statements today and I’ll point you to the discloser statement in our MD&A financial results materials for this call and news release. We certainly seek Safe Harbor under forward looking statements. So I’m going to start by saying that our 2015 results were heavily affected by foreign exchange losses due to the strength of U.S. dollars against the Canadian Dollar and the Icelandic ISK. These results mask what was really our best year ever, in revenue growth, production results and operational growth. As we financed and completed construction of Shannon Winter Farm in Texas and continue to do successful development of our Jimmie Creek, the hydro project in British Columbia and made big investment in Iceland, that will collectively result in continuing growth across the board in 2016 and future years. So I’m now going to let our great management team in Vancouver tell you more about our 2015 results and outlook. Starting with Alterra’s CEO, John Carson. John over to you. John Carson Thanks Ross, and I echo your thoughts about this being a successful quarter for us. I’d like to introduce the management team that will be joining me on the call here as well. First our CFO, Lynda Freeman, who is back with us full-time. Secondly though our recently moved, Interim CFO, Lindsay Murray who did a great job in Linda’s absence, so both of them are here with us and we are very fortunate to have both of them on our team. Over on the asset side we have Jay Sutton, our Head of Hydro, and Paul Rapp our Head of Geothermal and Wind Operations. As well as Murray Kroeker who is our Head of Engineering and Solar. And then also Jon Schintler who heads our project finance teams. To start the presentation I’d first like to call your attention to the cover of the presentation which you found on our Web site, just to see the asset, the Jimmie Creek asset under construction. It’s a very exciting time for our company as this asset is under construction and there you see the intake at the top of the asset and this is just an early stage of construction still, but you can see that it’s really quite developed already and we are on target to deliver this project ahead of schedule and on budget or ahead of budget by the summer of 2016, so very exciting time for the company. With that I’d like to turn to a review of our 2015 year-end financials and Lynda Freeman is going to provide that. Lynda, over to you. Lynda Freeman Thanks John and good morning everyone. 2015 was a busy but exciting year for Alterra. You’ll hear throughout presentation about the successful completion of construction of Shannon, the ongoing construction of Jimmie Creek, which is on time and on budget and about the strong performance of our operating assets. All of these factors had a significant impact on the annual results of the company as released yesterday. Before I go into more detail on these topics, I’ll start my presentation with the discussion on the operating results of the company on a consolidated basis. To those of you following on the presentation, Slide 4. The company’s consolidated revenue growth profit and adjusted EBITDA rolled down against 2014. However, I must highlight that this decline is almost entirely driven by unfavorable foreign exchange movements, with the Canadian Dollar and Icelandic krona weakening 19% and 13% respectively against the U.S. dollar. Other income and expenses remained consistent year-on-year, despite the significant movement to balances that within that cash. Specifically, non-cash movements in the embedded derivative, foreign exchange and non-recurring write-offs in the prior year. The company continues to record results from operating projects Toba Montrose and Dokie 1 as equity investments and in 2015 included the results of Shannon from commencement of operations on December 10th to the end of the year. That brings me on to talk about Shannon. During the year the Company went from owning 100% of a construction asset on January 1st to owning 50% equity interest in a fully operating project in December. To get to that point the Company completed construction financing, tax equity investment and incidental power hedge during the year. With commencement of commercial operation in December, this was shortly followed by full funding of tax equity on December 14th and resulted in a return of capital to Alterra of $3.5 million for unused construction contingency. Including this return of capital, the Company has invested $59 million in Shannon for our 50% fund-to-equity. Consistent with the previous period the Company believes the clearest view of our operating results is by looking at the net interest results by reflecting our ownership interest to Toba Montrose of 40%, HS Orka 66.6%, Dokie 1 25.5%, and now Shannon at 50%, reflecting our 50% sponsor equity in the project, as demonstrated on Slide 6 and 7 for those of you following our presentation. Fleet wide performance was 99.6% budgeted generation with record high generation at both Toba Montrose and Dokie 1. Once again the effect of the strong U.S. dollar can be seen in our results with revenue and adjusted EBITDA down year-on-year. Net interest in revenue was down 16% to $71.6 million and we recorded adjusted EBITDA of $37 million down 10% against 2014. I would like to highlight that in originating our functional currency, the operating results of Toba Montrose, Dokie 1, and HS Orka were all up year-on-year as presented in Slide 8, with increased generation at Toba Montrose and Dokie 1 and greater retail sales at HS Orka driving the increase. Moving away from our strong operating results to our balance sheet and Slide 9 in the presentation, we recorded net assets of $199 million at December 31st against $214 million in the prior year with foreign exchange and the fair value of the embedded derivatives the key drivers for the reduction in value. Looking at our cash and working capital, you will note that our cash position declined significantly. This was due to the investment in Shannon, repayment of loan to HS Orka and capital spent. At December 31st the Company is showing a negative working capital of $123 million due to the inclusion of the Company’s holding Company bonus held by Magma Energy Sweden of $180 million being classified as a current liability. These bonus were issued in conjunction with the acquisition of HS Orka back in 2010 and they’ve become due in July and December of this year. The bonds are non-recourse for the Company and are secured on a portion of our shares held of HS Orka. The Company is in the process of refinancing the bonds. However if the Company is not able to or elects to not refinancing the ISK bond which becomes due in July, the Company would lose 1 billion shares of HS Orka and our interest would fall to 53.9% we would continue to consolidate the results of HS Orka in this instance. Should the Company be unable to or elect to not finance either of the bonds then our share in HS Orka would be reduced to 21.8% and we would no longer consolidate their results. We do not see this as a likely outcome. Excluding the bonds in HS Orka from working capital, the Company has a positive working capital of just over $2 million. In addition, the Company received project dividends from Toba Montrose and Dokie 1 of over CAD5 million in early 2016. The Company has access to additional funds to finance further development including additional holding Company level debt and use of the revolving line of credit which has a current unused capacity of CAD20 million. Moving on to long-term debt on Slide 11. The Company through HS Orka has continued to lay down debt with over $17 million paid off in 2015. I just like to remind everyone that HS Orka is quickly paying off its outstanding debt with repayments falling significantly over the next few years. I refer you to Appendix 1 for details of repayments. HS Orka has significant leverage to support additional financing due to the reduction in the debt over the years. All other long-term debt both at hold current and project level have met all required debt service and covenant requirements. The last Slide and item that I am going to talk to is the inclusion of forecasted results to 2016 and ’17 in our MD&A. This is the first time we’ve included the outlook and we hope our investors find the information useful. The Company is forecasting net interest and generation of 1,610 gigawatt hours and 1,706 gigawatt hours in 2017, up 29% and 37% for 2016 and ’17 respectively largely due to the recognition of 12 months generation from Shannon and the inclusion of Jimmie Creek which is expected to come online in the summer of 2016. In addition, generation forecast reflects successful reinjection at Reykjanes and new production wells at Svartsengi. Based on internal budgets and forecast management expect the adjusted EBITDA on a net interest basis to grow 10% in 2016 and 30% in 2017 due to inclusion of Shannon and Jimmie Creek and an expected margin increase at HS Orka due to lower forecast power purchases following the increase in forecast generation. Regarding all other assumptions I refer you to our management discussion and analysis for full details. That concludes my update I now hand it up to John. John Carson Thanks Lindsay, Great. Thanks very much for that and now we’re going to move on to the operating section. I’m going to turn over to Jay Sutton to let us know what’s happening on the hydro side starting with Toba Montrose. Jay? Jay Sutton Thanks John. Referring to Slide 13, TMGP had a successful fourth quarter of 2015 producing 81 gigawatt hours of energy versus our forecast of 83 gigawatt hours and achieving our annual generation target on 8th of October which was 10 days ahead of the record set in 2014. The fourth quarter capped off an exceptional year with the plants generating a 111% of our 2015 forecast and establishing a new generation record of 792 gigawatt hours. We continue to make improvements for the plant, increase efficiency and generation, we spent the last two months performing annual maintenance in preparation for the higher inflows that will start in April. Our flow utilization and availability which are key measures of the plant performance both remain above 95%. For 2016 we’re at 91% of our forecast generation through the end of February and the snow packs above the long term average for this time of year. So we’re looking forward to a good generation through the spring and summer. Our crews continue to operate and maintain the plant safely and within our environmental commitments and we are now well over two years without a recordable incident for our employees or our contractors. That’s it for Toba Montrose, John. Back over to you. John Carson Great, with that let’s turn over to look at the Wind and Geothermal operation side, Paul Rapp. Paul Rapp Thanks John. I direct everyone to Slide 14 for our Shannon project. Shannon was a huge highlight for the company as Ross said in the introduction. In 2015 we completed construction on schedule and on budget and commenced commercial operations at Shannon on December 10th, 2015. This facility is operating very well. We’ve contracted with GE to provide wind turbine and balance plant maintenance at Shannon and the GE team onsite is doing a great job. Generation has tracked very close to plan for the first three months of operation and we were at 97% of plan year to date at the end of February. Turbine availability has also been high averaging over 97% year to date. We’ve had very few break in issues with the turbines or with the balance of plant. We are currently selling our power into the merchant market in Texas until the start of our hedge in June. Current merchant pricing is lower than forecasted historically low gas prices, but we expect this impact will largely go away upon commencement of our hedge in June. I’ll move on to our DC operations here. Dokie 1 on Slide 15. So the Dokie wind farm had a great year, performed exceptionally well in 2015 and achieved 339.8 gigawatts hours of generation or a 103% of the annual planned generation. This is the highest annual generation for Dokie since COD. Because of this Alterra receives an additional earn out payment of $750,000 from Axiom Infrastructure which was associated with the sale of 50% of our interest in Dokie two years ago. That sales agreement allowed for an additional payment of $750,000 per year for the three years following the sale when Dokie wind farm achieved greater than planned generation. So that was a nice little bonus for us. Strong production continues in 2016 and year to date production is 98% of plan through the end of February. Our assets [ph] continue to do a good job of maintaining our turbines at Dokie and at 2015 availability averaged 96%. Overall the Dokie facility continues to operate well with no safety or environmental issues and no significant equipment issues. I’ll switch over to highlights of our geothermal operations in Iceland now. Please refer to Slide 16. So both Svartsengi and Reykjanes plants performed well in 2015 and the overall production was 95.5% of plan for the year. Year to date we’re 101% of plan. Highlights at the Svartsengi plant for the year included drilling of two new wells, Svartsengi 25 and 26, both of which are showing very promising indications for production. The holes were just recently completed and down haul logging and flow testing is underway in these holes and we expect at least one of these holes will be connected to the plant in 2016. There’s ongoing construction at Svartsengi of a new discharge facility which will dispose of brine from the plant and this will allow for extraction of more geothermal fluid from the field and potential increase in power production from the plant as well. Over at Reykjanes we completed just in the last few weeks the reinjection pipeline that’s been under construction for a while there and this connects the plant to the previously completed RN 33 and RN 34 well area. Reinjection has commenced into those wells and will be ramped up over the next short while to provide pressure support to the Reykjanes field. That’s it from me. John I’ll hand it back to you. John Carson Great. Over to you Jay for a construction update at Jimmy Creek. Jay Sutton Thanks John. Referring to page 17, contractors working at Jimmy Creek made great progress in Q4 of 2015 and the civil portion of the project is now nearly complete. So the contractors have started to demobilize from the site and we are starting to reduce the size of the camp as the number of workers onsite decreases. We completed construction of the intake in January and filled the head pond in early March. We are currently performing final commissioning tests on the gates and the contractors are cleaning up the intake and demobilizing. On the Penstock, construction and remediation are both complete. We’ll perform a final lock through of the Penstock actually next week and are scheduled to fill and pressure test the Penstock by the end of March. In February we completed construction of the switch yard and performed final testing and commissioning of all the switch yard and transmission line equipment. The Jimmy Creek plant was connected to the Toba Montrose transmission line on the 1st of March and then at the powerhouse installation of the turbine generation of about 75% complete and you can see in the photo there the insulation of the starter over top of running of Jimmie Creek 2 and the contractors are now performing final electrical insulations and mechanical piping to prepare the units for testing and commissioning which we expect to start in April. As John mentioned, the project remains on budget and schedule and we’re looking forward to generating electricity in the second quarter of 2016. Over to you John. John Carson Thanks Jay. And now I’m going get to the section of looking ahead and where our energy to focus here in 2016. Before I do that, we need to make one correction in the presentation that was posted this morning. On Slide 12 in the outlook table we had a defunked table actually and I just like to clarify the numbers and these are the numbers that are identical with what we have in our news release and our MD&A generation for 2016 is 17, at 1,600 gigawatt hours and 1,700 gigawatt hours respectively. Total revenue is 92 million and 100 million respectively and adjusted EBITDA is 41 million and 48 million respectively. The presentation is being uploaded or re-updated as we speak and the correct numbers will be in that table. Apologies for that inconvenience there. Now looking to Slide 18, looking ahead. As most of you may have heard, there has been an extension of two renewable generation incentives in the United States which plays right into what we like to do which is to displace carbon generating activities with our clean renewable power projects. It was a two year plus tail extension of both the production tax credit which is typically used for wind projects and the investment tax credit which is typically used for solar projects. This really opens up the playing field for Alterra and plays right into our expertise of having a deep understanding of tax focused transactions such as the one we used at Shannon. And so we are directing our energies there and we’re working on several projects in the USA. First on the Greenfield side, we did lock up two projects with land leases very recently and we projected these two projects can have a capacity of up to 350 megawatts and we’re looking at other Greenfield projects currently as well. So this has been a major boon for us and we’ve decided to take advantage of it by ramping up on the Greenfield side. Also we’re analyzing several development stage acquisition opportunities in the states some of these are wind in fact most of them are, some of them are solar, but most all of these projects that we’re currently analyzing for acquisition are in the USA. Our teams are very busy working on this right now and really crystallizing what our next near term growth pipeline is going to look like. And finally in both Canada and Iceland we are advancing multiple hydro development projects such as Tahumming in British Columbia and Breuer, Verkin and Cavallo [ph] in Iceland. We’re very excited about these opportunities and looking forward to where we can really find the most opportunistic advancements for our development pipeline and we’ll also look at expansion on to our geothermal project we’ve long been discussing our Reykjanes plant and potential expansions there. There is one potential expansion the first portion of it which doesn’t involve drilling any new wells it’s basically just adding on a binary power unit to the existing facility there and we’re currently working that one as well. So what we see here at Alterra is really a good platform for growth in North America especially in the United States and we are fully exploring it, taking advantage of it and working to maximize our opportunities there for our shareholders to grow new and profitable projects that are generating clean renewable energy. With that we’re through with the core of our comments. Ross, I’ll turn it back over to you. Ross Beaty Okay. Thank you very much John. And I think I’ll just wind it up as John [technical difficulty], a good year operations last year and those results trying to somewhat by the flows on foreign exchange fluctuations to the U.S. dollar but certainly are setting ourselves a great year in 2016 and ’17 and beyond. So with that operator I think I’ll close the call presentation and open it to questions now. Question-and-Answer Session Operator Thank you, Sir [Operator Instructions]. Please stand by for your first question, which will be coming from Marin Katusa at KCR Fund. Please go ahead. Marin Katusa Ross and John great work guys, couple of quick questions. No mentioned of the dividends where we’re at with that? Ross Beaty So Marin we’re still debating that at our board level, we had more business of course had extensive discussion on that and we haven’t resolved yet what we’re going to do. Of course we’re disappointed that the foreign exchange strengths in the dollar our initial strength in the U.S. dollar has turned our free cash flow when described in U.S. dollar terms and to some repayouts impacting our deliberations on dividend. So right now, it’s a, watch this space kind of thing and we’ll have to report later on that. Marin Katusa Any hedging strategy that you guys are looking at, for the FX? John Carson Currently no hedging plans in effect as of today. You know it’s something that we monitor closely but I think you know that we don’t see or project any substantial currency movements in the near term. Lynda anything else to add there? Lynda Freeman The only thing I’d add is that currency fluctuations we’re seeing, mainly in our reporting currency, that’s a big impact that we say [Multiple Speakers]. John Carson That’s right and originating currencies as Lynda explained, we’re quite profitable in fact doing better. Marin Katusa Got you. Now the second quarter I got John, specifically to you. This really spit out the green field wind development the least for two U.S. projects up to 350. That’s very significant but what else can you tell us about it. Where, what and knowing Ross I’m sure he’s got a plan to how to finance that. Is Berkshire in the works or Starwood, like what’s the plan there, that’s pretty significant? John Carson Sure, it’s this two new projects we know purposely waiting to release more details, just a little bit later. We’re looking at multiple locations in the USA, for those more information to come on the precise locations. With respect to financing you mentioned Berkshire Hathaway which was a substantial participant in our Shannon project. Great relationship there. It would be you know not a surprise at all to me if they were participating in our next USA wind project, although you know there’s no commitments or anything else. I’d say that even if it weren’t you know the participants we had at Shannon, if it weren’t Berkshire, if it weren’t Citi there are plenty of other viable financiers for our next renewable energy projects. We have here at Alterra strong relationships with almost all USA tax equity providers and major project lenders. So could be any number of those providers Marin, but I do expect that there’s no shortage of capital for good projects today, so not a concern at all there as far as raising the debt or tax equity capital. Marin Katusa That’s great news. Jay this one would be for you. The Q4 on Toba generation was significantly lower than 2014 Q4. Was it just a — was there anything particular relating to the flow or was it in a capital issue or what was the reason of about 30% lower quarter-over-quarter. Jay Sutton No, just last year we had really high, we had a mild winter so we had much higher flows at the end of the year and at the beginning of 2015 so it was strictly related to just a water flows. Marin Katusa Lynda the last question from me, sorry for hogging so much time here, but when we look at the lump sum payments for the HS Orka loans over the next four or five years looking you know 17, 15, couple of 12s and a eight and I get that point how we’re dumping the — decrease that significantly but in this market with this project would be this is what I’d call like hot green debt you could refinance the 75 million HS Orka loan quite quickly. Is the company looking at doing the HS Orka loans at the same time as the Swedish debt or is the plan, no we’re just going to pay down the debt. John Carson Lynda and I are looking at each other here Marin, but let me speak up first on that one. It’s always a consideration and there is as you recognized there is a great deal of financing capacity at the HS Orka corporate level. So we have had some preliminary discussions around that and that is a possible outcome in the future. That said our first priority is to really finance the holdco loans, the Sweden House holding company loans. Those term out at the end of the year and that’s why our efforts are put there first and foremost and those activities are well under way. We have an advisor working for us, we’re really just kind of getting everything in line to get that done in a good way. So that’s where the focus is but yes there would be plenty of financing capacity at the HS Orka level. We’ll be looking at that in the future. My last statement about that is if and as we develop the Breuer [ph] and hydro project which I mentioned, or the Reykjanes 4 expansion, which I also referred to in the growth section, we may do a project related refinancing or new financing as well to supplement or complement the existing HS Orka loans. So a lot of interesting backdrop for Icelandic related financing, but to reiterate first and foremost we’ll be refinancing these holdco loans. Marin Katusa Very exciting, thanks all. Operator Thank you, your next question will be coming from Steven Hong at National Bank, please go ahead. Steven Hong Hi, this is Steven filling on behalf of Rupert. Just had one question with regards to Mariposa, Chile project, also maybe you could give us more additional color, just the fact that it was postponed in October 2015. John Carson Okay sure, that was a disappointment for us, we referred to I believe on our last call. We had originally planned to commence this drilling in late 2015 October and we announced you know upon postponement at the elections of the management partner of the project, our partner EDC Energy Development Corporation. They chose to defer this drilling for a year based on certain factors that were occurring in Chile, primarily a reduction in commodity prices which gets reflected in reduced forward power prices which affects the level of contracting that this project could get in Chile. In other words there seemed to be a negative spike in commodity prices and we’re going to you know they wanted to wait that out a little bit or to reassess. That was their decision to make, and we announced at that time that it would be deferred until late this year. So that’s currently the plan and who knows ultimately whether they will do it this year or defer further. We hope that certainly it occurs this year, sooner the better in our view. But in the end that particular decision is reserved for our partner. Steven Hong Okay, that’s all I have for today, thank you. Operator Thank you, [Operator Instructions], and currently Mr. Beaty, Mr. Carson we have no other questions registered. Ross Beaty Okay, thank you operator. We’re getting off lightly today. In that case we’ll end the call and thank again everyone for participating today. If you have any further questions you can certainly call our office in Vancouver and speak to any of the participants that have been talking today for any further details. Any comments John? John Carson No Ross, other than to say that I’d call everybody’s attention to the revised presentation on the website it has been revised the proper table on slide 12 is now there. Ross Beaty Okay, thanks very much and thanks again everyone for joining us, we’ll end the call now, thank you operator. Operator Thank you sir, ladies and gentlemen this does indeed conclude your conference call for today. Once again thank you for participating and at this time we do ask that you please disconnect your lines, enjoy the rest of your day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. 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