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Otter Tail’s (OTTR) CEO Chuck MacFarlane on Q4 2015 Results – Earnings Call Transcript

Operator Good morning and welcome to Otter Tail Corporation 2015 Earnings Conference Call. Today’s call is being recorded and there will be a question-and-answer session after the prepared remarks. I will now turn the call over to the Company for their opening remarks. Loren Hanson Good morning, everyone and welcome to our call. My name is Loren Hanson and I manage the Investor Relations area at Otter Tail. Last night, we announced our 2015 results and issued 2016 guidance. Our complete earnings release and slides accompanying this earnings call are available on our website at www.ottertail.com. A replay of the call will be available on our website later today. With me on the call today are Chuck MacFarlane, Otter Tail Corporation’s President and CEO and Kevin Moug, Otter Tail Corporation’s Senior Vice President and Chief Financial Officer. Before we begin, I’d like to remind you that during the course of this call, we will be making forward-looking statements. These forward-looking statements are covered under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995 and include statements regarding Otter Tail Corporation’s future financial and operating results, or other statements that are not historical facts. Please be advised that actual results could differ materially from those stated or implied by our forward-looking statements due to certain risks and uncertainties, including those described in our most recent Form 10-K and subsequent quarterly reports on Form 10-Q. Otter Tail Corporation disclaims any duty to update or revise our forward-looking statements as a result of new information, future events, developments or otherwise. For opening remarks, I will now turn the call over to Otter Tail Corporation’s President and CEO, Mr. Chuck MacFarlane. Chuck? Chuck MacFarlane Good morning and thanks for joining our call. During the last several years, Otter Tail Corporation has been moving toward a business model with two platforms and one common vision. Result is a focused manufacturing platform combined with a core utility platform. Our vision includes attention on growth, operational excellence, talent development. The electric platform continues to execute on a robust rate base expansion effort. Slide 5 shows our rate base expansion and a compound annual growth rate of 8%. This has been adjusted to account for the impacts the recent five-year extension to bonus depreciation and additional renewable and natural gas generation projects. During the 2016 to 2020 timeframe, Otter Tail Power plants to make $858 million capital investments. Slide 6 shows our regulatory framework, which continues to be constructive. As noted on the bottom of the slide, half of the projects are eligible for rider recovery while under construction. And the majority of the balance of the capital spend is at current depreciation levels effectively in existing base rates. Presence of our manufacturing and plastics companies continue to guide improvement in each of their businesses. And I’ll discuss some of the examples in a moment. All of our operating companies focus on our long-term compound annual earnings per share growth goal of 4% to 7% as measured from 2013 earnings per share of $1.50. While we’re currently below this goal, we are confident we will be back in this range given our pipeline of rate base projects and our effort to return our companies to historic return on sales levels when the current down cycle manufacturing segment improves. Otter Tail Corporation ended 2015 with earnings per share of $1.56 from continuing operations, a return on equity of 10% and a dividend yield of 4.6%. We accomplished this by managing through difficult end market conditions in our manufacturing segment. In addition, tax law changes made late in the year negatively impacted our consolidated results. Kevin will cover this in more detail. Otter Tail Power’s results benefited from strong project management and regulatory recovery. And despite weather challenges, Otter Tail Power finished the year with 10.7% increase in net income. Of note, Big Stone plants’ air quality control system reached commercial operation on December 29, ahead of compliance deadlines and under budget. Looking ahead, construction has begun on 70-mile 345-kv transmission line running from Big Stone South substation to Brookings, South Dakota. This should be completed in 2017 The structure will begin in mid-2016 on a 170-mile line from Big Stone South substation to Ellendale North Dakota with an expected completion date of 2019. In addition, Otter Tail Power management is evaluating options for natural gas plant given the plant retirement of Hoot Lake Plant in 2021. Otter Tail Power’s Minnesota approved integrated resource plan calls for up to 300 MW of additional wind energy by 2021, and before 2020, enough solar to power 1.5% of Minnesota retail sales. This equates to approximately 30 MW of new solar. Today, 19% of the Company’s retail load is served by renewals. The extension of the renewable production tax credit and the investment tax credit will benefit customers by allowing Otter Tail Power to continue adding low-cost renewables to the supply portfolio. One more utility item before turning to the manufacturing platform is to let you know that we will file a rate case in Minnesota before the end of the month. This will be the first Minnesota general rate case since 2010. More details will be available after the filing. Our manufacturing companies continue to be impacted by economic headwinds in agriculture and energy end markets, and the general contraction in US manufacturing. While we continue to position them for future growth. For example, BTD’s Minnesota optimization plan is on track. By the end of the first quarter, the Detroit Lakes portion of the plan will be complete. And a new state-of-the-art paint line is already operational in the expanded Lakeville facility. BTD’s world-class OEM customers are impressed with the facility and we expect to receive paint system approval from all remaining OEMs by the end of the first quarter. Another example positioning for the future growth is BTD’s September acquisition of Impulse Manufacturing, now known as BTD-Georgia. Integration is going well. BTD-Georgia has made significant progress on integrating the estimating function as increased services and improved on-time delivery. Vinyltech and Northern Pipe Products, our plastic segment, a 2015 results similar to those of 2014, which is evidence of a nimble management team that managed through reduced demand and declining sales in resin prices. Overall 2015 included a number of important events for Otter Tail Corporation. We have captured some of the highlights on slide 8. In addition to what I’ve already discussed, the EPA announced its final Clean Power Plan rule, Otter Tail Power continues to work with stakeholder groups at states develop their implementation plans. Survey results from two nationally recognized customer satisfaction firms rated Otter Tail Power highest in overall customer satisfaction among electric utilities in various categories. And the John Deere plant in Fargo, North Dakota recognized BTD with its highest supplier award. And Vinyltech set a record for pounds of pipe sold in 2015. Now I’ll turn it over to Kevin for the financial perspective. Kevin Moug Good morning. Our guidance for 2015 was to be in the middle to upper half of the range of $1.50 to $1.65 a share from continuing operations. This was based on current tax law at the time the guidance was issued. We also disclosed this guidance could be reduced by $0.02 to $0.04 a share if the tax law was changed. The federal government did change the tax law on December 18, 2015. A large amount of capital we placed in service in December of 2015 combined or taking [ph] bonus depreciation put us in a consolidated net operating tax loss for the year. As a result, we weren’t able to take Section 199 deduction but did pick up the research and development credits that is now permanently placed in the tax law. And our 2015 results were negatively impacted by $0.03 a share. Without the effects of the tax law changes, our earnings per share from continuing operations would have been in the middle to upper half of the guidance range we had previously given. Please refer to slide 9 for an overview of 2015 earnings from continuing operations. Our electric segment had strong earnings in 2015 in light of milder weather. The key factors of the $4.7 million increase in net earnings were increased environmental and transmission costs recovery riders, increased conservation incentives and increased sales to pipeline customers. Year-over-year, weather negatively impacted earnings per share by $0.08. And compared to normal, weather negatively impacted earnings per share by $0.05. Lower operating and maintenance travel and administrative costs also favorably impacted earnings. For our manufacturing segment, net earnings declined between the years at BTD by $4.9 million and at T.O. Plastics by $200,000. An overview of these results by each company is as follows. BTD’s revenues declined $6.6 million due to continued softness in sales to customers served by BTD in agricultural as well as oil and gas end markets, lower scrap sales due to a reduction in scrap metal prices and a reduction in scrap volume related to lower production and the sales volume. Softness in scrap metal prices continues to be plagued with excess steel capacity in the US market and low-priced steel imports. Scrap revenues as a percentage of part sales were 4% in 2014 compared to 2.2% of parts sales in 2015. This item alone accounted for $1.9 million reduction in net earnings between the years and lower tooling revenues also contributed to BTD’s revenue decline. These declines were offset by additional revenues of $8.8 million from the BTD Georgia acquisition in September of 2015 and BTD’s results were also negatively impacted by higher costs and expedited freight, manufacturing consumables and cost of quality. T.O. Plastics’ revenues increased $2 million as a result of increased sales in horticultural and custom products, but while these revenues increased year-over-year for T.O. Plastics, margins declined due to a change in product mix. Our Plastics segment earned $0.32 a share in 2015 compared to $0.33 a share in 2014. Revenues declined year-over-year mainly due to lower PVC pipe prices. Pounds sold were down 1.4%. Earnings, however, were flat as we were able to maintain operating margins in light of declining sales prices and our corporate costs were $0.16 a share compared to $0.22 a share in 2014. Since 2013, corporate costs have been reduced by more than 36%. Please move to slide 12 for a discussion of our 2016 business outlook. Our 2016 earnings guidance is expected to be in the range of $1.50 to $1.65 earnings per share. This guidance reflects our current mix of businesses and the current economic challenges being faced in our manufacturing platform. Our Electric segment’s 2016 net earnings are expected to be slightly higher than 2015 based on normalized weather for 2016, a constructive outcome of the Minnesota rate case, which is expected to be filed before the end of February 2016, rider recovery increases including riders in Minnesota and North Dakota related to the Big Stone Plant AQCS environmental upgrades and transmission riders related to CapX2020 and increased investments in MISO MVP transmission projects, Increased volumes from pipeline and commercial customers and lower pension costs as a result of a decrease in projected benefit expenses due to an increase in the discount rate. These items are primarily offset by the effect of the 2015 adoption of bonus depreciation for income taxes which reduces 2016 earnings by $0.06 a share, higher depreciation and property tax expense due to large capital projects being put into service, higher short-term interest costs to fund major projects and increasing operations and maintenance expenses. BTD, in our manufacturing segment, has significant exposure to the ag, oil and gas and recreational vehicle end markets. Customers served in these end markets are forecasting 2016 sales to be lower than 2015. Despite these challenges, we expect increased net earnings from our manufacturing segment in 2016 due to increased sales at BTD Georgia due to a full year of ownership. Expected full-year sales for BTD Georgia are $33 million. Excluding the full-year impact of the BTD Georgia, revenues are planned to grow approximately 7% based on BTD’s new paint line being placed into service in January of 2016 and its expected impact on sales growth and improved operating margins from improved productivity and efficiencies gained in our manufacturing processes. These items are offset impart by continued lower scrap revenue due to lower commodity prices from excess capacity and lower-priced imported steel. Scrap revenue is currently expected to be about 1% total part sales for 2016 and higher facility costs associated with BTD’s expansion. T.O. Plastics’ earnings are expected to be lower in 2016 primarily due to a shift in product mix and backlog for this segment is approximately $134 million for 2016 compared with $140 million a year ago. We expect Plastics segment net income to be down from 2015 as sales volumes are projected to be flat compared to 2015 and lower operating margins are expected due to tighter spreads between raw material costs and sales prices along with increased labor and trade and we expect corporate costs to be lower in 2016 compared to 2015. On February 5, 2016, we issued a $50 million two-year note with an ability to borrow an additional $50 million with lenders’ consent. Proceeds were used to pay down borrowings on the line of credit used to fund BTD’s Minnesota facility expansion as well as fund the BTD Georgia acquisition. The borrowing costs under this facility are lower than the interest costs of our corporate credit facility. This facility also positions us to have a backstop to retire the remaining $50 million of 9% notes due in December of 2016. Let me provide an overview of our capital expenditure plans as shown on slide 14. We expect capital expenditures for 2016 to 2020 to be $858 million for the electric utility. This is an increase over our previous year’s guidance as we have included additional wind and solar projects as well as the completion of our natural gas generation facility. We expect capital expenditures for the manufacturing platform to be $114 million over the same time period. Our updated compounded annual growth rate in rate base is 8% from 2014 through 2020. This reflects our updated capital plans and the impact of the recently extended tax loss related to bonus depreciation. Our need for equity over this timeframe before the change in bonus depreciation was in the range $140 million to $150 million. We expect this need to be reduced by $25 million to $35 million as a result of the extended bonus depreciation. We also expect to use our existing stock programs to satisfy these equity needs. Based on our solid 2015 performance and the 2016 outlook, the board of directors increased our indicated annualized dividend rate from a $1.23 a common share to $1.25 a common share. Our 2016 guidance is dependent on the business and economic challenges our two platforms face in 2016. Key initiatives include a constructive outcome of a rate case expected to be filed in Minnesota by the end of February 2016, BTD’s successful growth in sales from its new paint line along with our operational improvements needed to further improve our return on sales margins, and full integration of BTD’s new facility in Georgia to better serve our growing customer base in the Southeast. These are key initiatives that must be successful in light of continuing end market softness in ag, oil and gas and recreational vehicle and continued strong earnings, cash flows and returns on invested capital in our Plastics segment. We remain confident in the future earnings ability of our two platforms to meet our long-term stated growth goals of 4% to 7%, compounded annual growth rate of earnings per using 2013 as the base year. We are now ready to take your questions and after the Q&A, Chuck will return with a few closing remarks. Question-and-Answer Session Operator Thank you. [Operator Instructions] Thank you. And our first question comes from the line of Paul Ridzon with KeyBanc. Your line is open. Paul Ridzon Good morning. When do you expect Minnesota rates to kick in? Kevin Moug We would anticipate a filing by the end of February. There is a 60-day period within the filing complete and so interim rates would go in by May 1. Paul Ridzon May 1? Okay. And then with the drilling slowing down, you’re forecasting higher pipeline sales, is that just the system is still backfilling with takeaway capacity? Chuck MacFarlane The majority of our pipeline load is associated with Canadian oil, not directly with drilling in the Bakken and a majority of those capital processing investments in plants in Canada continue to operate. Paul Ridzon And then what’s driving higher sales to commercial customers? Chuck MacFarlane Paul, we just collectively have grouped the pipeline in the commercial sales together and the increases in — it’s mostly the pipeline. Paul Ridzon And then, if we pro rate, I think 8.8 million that Georgia earned since September 1, that gets me about $26.4 million on an annual basis, but you’re forecasting 33. Is that business ramping, are you realizing some synergies or what drives that increase? Was it just seasonality? Kevin Moug Yes. Well, we’re expecting additional — as a result of the acquisition, we’re expecting additional volumes coming from other customers that BTD was serving before the acquisition that we can now also better serve them down in the south-east. Paul Ridzon So is it revenue synergy and cost synergies? Kevin Moug There is revenue synergies and then there is cost synergies as well, but the 8.8 million just to clarify earned was, that’s revenue in 2015. And we’re forecasting approximately 33 million of revenue in 2016. So that’s roughly a $24 million increase. One just now the benefit of having it owned for an entire year plus some additional growth from being able to better serve customers in the southeast that we hadn’t been able to necessarily serve as a result of not having a location and then additional sales growth from some of the other customers that we’re serving there. Paul Ridzon Got it. Thank you. And then lastly, excluding Georgia, you are looking for revenues to be up 7% at BTD. What are the end markets that’s driving that increase? Kevin Moug Well, a lot of the stuff that’s coming is the bringing the paint line in effective here January, because we know there is additional opportunities with existing customer base as to now provide them additional product or services if you will, given that we have paint. So we would expect that that growth is coming across a number of the end markets as we’re now able to paint for egg, recreational vehicle and other lawn and garden and other end markets that we’re serving. Paul Ridzon And you’ve got, at this point, good visibility on that business coming in? Kevin Moug We have, as Chuck mentioned, we’re mostly qualified for — I think we’re expected to have remaining qualifications wrapped up by the end of the first quarter and the line [ph] is running. We were just there last Tuesday with our board and saw the line running and painting parts and so the visibility obviously, we’ve still got to go out and win the work, but we’ve got a line that’s operating well, it’s in service and it is past a number of the qualifications for paint specs by customers. Paul Ridzon Okay, thank you very much. Kevin Moug Welcome. Operator Thank you. [Operator Instructions] Our next question comes from the line of Mike Bates with Robert W. Baird. Your line is open. Mike Bates Good morning, gentlemen. How are you? I was hoping to get a little bit more color on your upcoming rate case filing. Can you talk to us a little about the expected breakdown in your F between just rolling rider recoverable projects in to rate base and things like that as opposed to evolution of your operating expenses, changes in demand forecast, things like that? Chuck MacFarlane Yes. I mean our case will continue to work, the riders will be in place and generally and at the finalizing of the case, we’ll roll some of those riders into, we would anticipate, the emissions equipment at Big Stone whatnot would be rolled into base rates. So our filing is an adjustment above what we’re getting currently in rider covered. Kevin Moug Mike, this is Kevin. Until the rate case is filed, there is really nothing that we can give in terms of additional detail on it. When we file the rate case, there will be an 8-K filing that we’ll go along with that and that will have more details in it. Mike Bates Sure. Absolutely. And don’t want to get too deep into the weeds before we have that finally in front of us. One other question though is, should investors expect to see a multi-year rate plan or would you expect it to be a more traditional single test year type of deal? Chuck MacFarlane It will be more a single test year, forward-looking test year, single year case. Mike Bates All right. And then any color you can offer in terms of when we might see rate cases filed in your other jurisdictions? Kevin Moug We will start in the middle of this year with our — as we do every year, our cost of service studies and allocations between jurisdictions and would make a decision probably earlier in the third quarter, if there would be any additional filings this year in either of the Dakotas. Mike Bates Absolutely. Okay. And just the last question before I hop off, in terms of your new generation resources we’re looking at, over the next several years, will you be required to hold a competitive RFP as we think about the likelihood of these projects being owned resources put into rate base as opposed to PPAs? Chuck MacFarlane We’ll continue to lease gauss planning, we currently are not under a requirement to RFP there in any other jurisdictions. Mike Bates And remind me, do you have the ability to get preapproval or predetermination for either type of resources? Chuck MacFarlane We have the ability in both Minnesota and North Dakota to file for a Advance Determination of Prudence on these facilities and also incorporate those into our integrated resource plan as filed with Minnesota, that plan, an update to that is due in June of ‘16. Mike Bates Excellent. Thank you very much. Operator Thank you. And we have a follow-up from Paul Ridzon with KeyBanc. Your line is open. Paul Ridzon What was the impact of weather versus normal for the full year? Sorry, if I didn’t get that? Kevin Moug The impact of weather versus normal was $0.05. Paul Ridzon So if we were to add that back to 15 results, you’re looking for a down year at the utility? Chuck MacFarlane Well, I mean weather is arguably offset by the first year in this bonus depreciation. Paul Ridzon Okay. That was $0.06 Chuck MacFarlane That was $0.06. Paul Ridzon Thank you for that clarification. Thanks. Operator Thank you. And this does conclude today’s Q&A session. I would now like to hand the call over to Mr. Chuck MacFarlane for closing remarks. Chuck MacFarlane Thank you. I’ll summarize by saying that we remain committed to a diversification strategy focused on two distinct platforms, manufacturing and the core utility. Our companies will continue to focus on customers and we’ll take a long term view. Our strategic objectives are to grow our businesses, achieve operational excellence and develop our talent. We thank all of our employees for their hard work and we thank you for joining the call and for your interest in Otter Tail Corporation. We look forward to speaking with you next quarter. Operator Ladies and gentlemen, thank you for participating in today’s conference. This concludes the program and you may now disconnect. Everyone, have a great day. 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Black Hills’ (BKH) CEO David Emery on Q4 2015 Results – Earnings Call Transcript

Operator Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Fourth Quarter and Full-Year 2015 Earning Conference Call. My name is Kat and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir. Jerome Nichols Thank you, Kat. Good morning, everyone. Welcome to Black Hills Corporation’s fourth quarter and full-year 2015 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. During our earnings discussion today, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, Slide 2 of the investor presentation on our website and our most recent Form 10-K, Form 10-Q, and other documents filed with the Securities and Exchange Commission for a list of some of the factors that could cause future results to differ materially from our expectations. I will now turn the call over to David Emery. David Emery Thank you, Jerome, and good morning, everyone. Thanks for participating in the call this morning. I will be following along here on the webcast presentation deck for those of you who have it. Starting on Page 3, we will follow a similar agenda to previous quarters. I’ll give a quick update on highlights of the quarter. Rich Kinzley will cover the financial update, and then I’ll jump back in for forward strategy before we take questions from all of you. Moving on to Slide 5, fourth quarter highlights, we had a real solid fourth quarter despite the fact that we had mild weather for our gas utility territories and a continued decline in crude oil and natural gas prices, which affected our oil and gas results. During the quarter, we made great progress on several key growth initiatives, including our pending acquisition of SourceGas. Related to SourceGas, we received regulatory approvals now in three states; Arkansas, Nebraska, and Wyoming. And our closing will occur as soon as we receive approval in the state of Colorado. We still expect to close sometime during the first quarter. We’ve also recently completed our permanent financing on both the debt and the equity needed to close the transaction, so we’re ready from our finance standpoint. We still have several teams working on detailed integration activity. We expect to be fully integrated all systems and processes by year-end 2016, assuming we get closed by the end of the first quarter. Moving on to Slide 6, utility highlights for the quarter, Black Hills Power received final approval from the Wyoming Public Service Commission to begin construction on the first segment of our new 144-mile transmission line that will go from northeastern Wyoming to Rapid City, South Dakota. We expect to start construction in February and have that line completed ad in-service by year end. At Cheyenne Light in Wyoming, we recorded a new winter peak load of 202 megawatts on December 28, 5 megawatts higher than the previous winter peak set the year before. At our Colorado Electric subsidiary, we received approval in October to purchase the $109 million 60-megawatt Peak View Wind project. That project will be built by a third-party wind developer and we’ve executed a build transfer agreement with them, and we’ll take over as soon as the project is in-service, which is expected at year end. At Colorado Electric, we also continued construction on our new $65 million, 40-megawatt simple cycle gas turbine, which we’re adding to the Pueblo Airport Generating Station. We expect that turbine also be in service by year end. Moving on to Slide 7, Non-regulated Energy and corporate highlights for the quarter. On the Non-regulated Energy side, we initiated process during the quarter to explore the sale of a minority interest in our Colorado IPP 200-megawatt combined cycle units at the Pueblo Airport Generating Station. That process is ongoing, and we expect to make a decision related to that potential sale in the first quarter. We also completed our 2014, 2015 Mancos formation shale gas drilling program in the Southern Piceance Basin to prove up, the extent to that resource. We drilled, completed and tested and now have on production nine wells. We have four additional wells that we drilled and cased. We deferred the completion activities on those four wells, because we have a limited amount of gas processing capacity out of the area and we won’t need them probably call, at least, next year to fill the plant capacity. Overall, the results of the drilling program exceeded our expectation, so we’re quite pleased with the results there. On the corporate side, last week, our Board of Directors declared a quarterly dividend of $0.42 a share, that’s equivalent to an annual dividend rate of $1.68. The increase to $0.42 represents the 46th consecutive annual increase in dividends to shareholder. During the quarter, we also entered into $400 million of interest rate swaps to mitigate interest rate risk associated with the future debt refinancing activity, we expect in late 2016 and early 2017. Moving on to Slide 8, this just simply provides a reconciliation of fourth quarter income from continuing operations as adjusted, the fourth quarter 2014 results. Strong performance at our Electric Utilities and Power Generation segments nearly made up for the negative weather impacts at our gas utilities and the low crude oil and natural gas prices that are oil and gas subsidiary that I mentioned earlier. Slide 9 provides a similar reconciliation for full-year 2015 versus full-year 2014. Again, despite the challenges, we’re still able to post an increase in net income as adjusted. Now, I’ll turn it over to Rich Kinzley to talk about the financials for the quarter and the year. Rich? Richard Kinzley All right. Thanks, Dave, and good morning, everyone. We are encouraged to report another year of earnings growth in 2015, driven by strong results at the Electric Utilities, Power Generation, and Coal Mining businesses. As Dave mentioned, overall results were tempered by unfavorable weather and low crude and natural gas prices. Our gas utilities faced warmer than normal weather in the winter heating months in 2015, compared to colder than normal weather in 2014, which contributed to a decline in year-over-year performance, and low commodity prices impacted our oil and gas business. But despite those challenges, we again delivered earnings growth in 2015. On Slide 11, we reconciled GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings to better represent our ongoing performance. This slide displays the last five quarters, in each of the last two years. In each quarter of 2015, we incurred a non-cash ceiling test impairment charge at oil and gas business, due to the continued decline of crude oil and natural gas prices throughout 2015. In the second quarter of 2015, we also recorded a non-cash impairment of an equity investment at our oil and gas business, due to low commodity prices. In the fourth quarter, we divested this equity investment and realized the small gain above the impaired book value. We also incurred external acquisition-related expenses like financing and other third-party costs, in the second, third, and fourth quarters of 2015 associated with the pending SourceGas acquisition. These impairments in acquisition expenses are not reflective of our ongoing performance and accordingly we reflect them on an as adjusted basis. Our fourth quarter as adjusted EPS reflective of ongoing operations was $0.71 per share compared to $0.77 in the fourth quarter last year. Our full-year as adjusted EPS was $2.98 for 2015 compared to $2.93 for 2014. Fourth quarter and full-year EPS were diluted by approximately $0.04 each due to the 6.3 million share common stock offering we completed in November to partially fund the SourceGas acquisition. Slide 12 displays our fourth quarter revenue and operating income. On the left side of the slide, you’ll note the revenue was lower in 2015, due to reduced revenues at our gas utilities from lower pass-through gas costs during the year, given the low natural gas price environment in 2015. On the right side of the slide, you see strong performance in the fourth quarter at our Electric Utilities and Power Generation businesses more than offset decreased performance at our gas utility, coal mining, and oil and gas businesses, resulting in a 4% increase in consolidated operating income compared to the fourth quarter in 2014 Moving to the full-year on Slide 13, revenue decreased by $89 million, again, due to lower pass-through gas prices in 2015 at our gas utilities. Operating income improved at our Electric Utilities, Power Generation, and Coal Mining businesses in 2015. These improvements were partially offset by lower earnings at our gas utilities due to warmer winter weather and wider losses at our oil and gas business due to the lower natural gas and crude oil price environment. In total, year-over-year operating income increased by over 7%. And excluding our oil and gas business, our core utility and utility-like businesses’ operating income increased by 13%. I’ll touch on each business in more detail in the following slides. Slide 14 displays our fourth quarter and full-year income statements. Before asset impairment charges and acquisition-related expenses, we delivered operating income growth for both the fourth quarter and full-year despite the weather and commodity price challenges mentioned earlier. We implemented cost management efforts early in 2015 and I’m pleased with the way the organization responded. You can see our operating expenses decreased in the fourth quarter and increased only 1.5% for the full-year. Depreciation and interest expense increased, as we continue to grow our asset base. We’ve broken out the non-recurring impairments and external acquisition-related expenses, including the cost of the bridge financing we arranged for the pending SourceGas acquisition. For the full-year, as adjusted EPS grew nearly 2% year-over-year, while EBITDA increased by over 7%. Slide 15 displays our electric utilities gross margin and operating income. The electric utilities gross margin increased in the fourth quarter by $6 million over 2014 and by $49 million year-over-year. These gross margin increases resulted primarily from return on additional investments most notably the $222 million Cheyenne Prairie Generating Station, which went into service October 1, 2014. New rates associated with these investments went into effect at all three of our electric utilities in late 2014 and early 2015. Gross margin also benefited from industrial and commercial load growth in a variety of other factors, as detailed in our earnings press release distributed yesterday. Strong cost management throughout 2015 resulted in reduced O&M in the fourth quarter of 2015 compared to 2014, and a full-year increase of only 5% despite 12 months of the Cheyenne Prairie plant in operation during 2015 compared to three months in 2014. The combination of gross margin improvement and strong cost management resulted in operating income increasing by $7.3 million, or 19% during the fourth quarter compared to 2014, and $36.1 million, or 25% for the full-year 2015 over 2014. The electric utilities had an outstanding year driven by large capital investments to better serve our customers. Moving to Slide 16, our gas utilities gross margin as compared to 2014 decreased $3.6 million in the fourth quarter and $7.3 million for the full-year, driven by 14% fewer heating degree days in 2015 compared to 2014. Both heating seasons comprised of the first and fourth quarters were milder in 2015 than 2014. Strong cost management efforts at the utilities – at the gas utilities with decreases in O&M for both the quarter and full-year compared to 2014, partially offset the negative weather impact. Operating income declined $3 million in the fourth quarter compared to 2014 and by $4.9 million year-over-year. Compared to normal weather, our gas utilities gross margins were negatively impacted by an estimated $4.9 million in 2015. Also, in 2015, our electric utilities gross margins were negatively impacted by an estimated $3.9 million compared to normal weather. Combined these negative weather impacts compared to normal impacted our EPS by approximately $0.13 in 2015. On Slide 17, you see the power generation improved operating income by $3.2 million for the fourth quarter compared to 2014 and by $5.7 million year-over-year. The main drivers in the improved operating income were an increase in megawatts delivered in 2015 due to a Wygen I outage in 2014 and a Wygen I power purchase agreement annual price increases, as well as lower maintenance expenses and general cost management during 2015. For the full-year, as adjusted revenue was $3.5 million higher in 2015 and as adjusted O&M, including depreciation was $2.2 million lower. On Slide 18, our coal mining segment had a $1.2 million operating income decrease compared to the fourth quarter in 2014. For the quarter, revenue was $2.2 million lower as tons sold decreased by 7% compared to Q4 2014, due primarily to planned outages. Further, our regulator approved pass-through mechanism through which we sell approximately half our coal, yielded a lower price per ton in the fourth quarter due to lower mining costs. In Q4, O&M was $1 million lower in 2015 than 2014. For the full-year, coal mining operating income increased by $1.7 million, while tons sold were 4% lower in 2015, due to planned outages we’ve benefited from a significant revenue per ton increase in mid-2014 on a third-party coal contract as a result of a contractually scheduled price re-opener. This contract represents approximately 35% of our production and a higher price per ton increased our revenue in 2015 by $4 million. Keep in mind, the revenue increase from this price adjustment did not drop straight to operating income, as we pay revenue related royalties and taxes on the increase. On the cost side, we enjoyed continued mining efficiencies and lower fuel costs. We moved 31% more overburden in 2015, but at a decrease per cubic yard cost. O&M was flat from 2014 to 2015. Moving to oil and gas on Slide 19, we incurred an operating loss in the fourth quarter of $5.8 million, excluding a $71 million pre-tax ceiling test impairment charge compared to an operating loss of $4.5 million in 2014. Fourth quarter production increased 45% from 2014, driven by a 67% increase in natural gas sales volumes. From an average price received standpoint, including hedges, crude oil decreased by 22% and natural gas decreased by 38% comparing Q4 2015 to Q4 2014. For the full-year, we incurred an operating loss of $27.5 million, excluding pre-tax ceiling test impairment charges of $250 million compared to an operating loss of $11.8 million in 2014. 2015 production of 12.9 billion cubic feet equivalent represented a 29% increase over 2014, driven by a 41% increase in natural gas sales volume with a 10% increase in crude oil volume, and a 24% decrease in NGL sales volume. Comparing 2015 to 2014 average prices received for the full-year, including hedges, natural gas prices decreased by 39% and crude oil by 24%. While we are pleased with the outcome of the drilling program in the Piceance Basin over the last couple years from an operational standpoint, the low commodity price environment in 2015 severely impacted financial results at our oil and gas business. Regarding impairments taken in each quarter of 2015, Slide 20 shows the average trailing 12-month crude oil and natural gas prices, which continued to drop each quarter in 2015, driving the impairments. Given the continued low price environment for crude oil and natural gas, it’s likely we will have additional non-cash impairments to our oil and gas reserves in 2016, at least, in the first quarter. However, any impairments will be much smaller than those recorded in 2015, as our full cost pool is impaired down to approximately $94 million at the end of 2015, with an additional approximate $68 million in excluded costs, which is made up of a certain infrastructure, assets, and wells drilled, but not yet completed. Impairments taken in 2015 are driving down our depletion rate and our current guidance estimates the depletion rate of $0.80 to $1.20 per Mcfe in 2016. It’s worth noting here that we are managing our go-forward exposure in our oil and gas business by cutting CapEx, reducing the cost structure of the business, and beginning to divest non-core properties. You can see in our press release yesterday, the trend in the fourth quarter related to reduced O&M. And as I just noted, we expect a much reduced depletion rate in 2016, given the impairments. Dave will further address our strategy around oil and gas in a few minutes. Slide 21 shows our capitalization. At year end, our debt to cap ratio was 57% with a net debt to cap ratio of just over 50, excuse me, 57% with a net debt to cap ratio of just over 50% given cash on hand. In November, we received net proceeds of $536 million from the issuance of common stock and unit mandatory convertibles to partially fund the pending SourceGas acquisition, which increased our equity and debt. In January, we issued $550 million of long-term debt to nearly complete the permanent financing required for the acquisition. We will be assuming approximately $760 million of SourceGas debt when we closed the transaction. The remaining financing needs at closing expected to be in the range of $50 million to $100 million will be covered with our revolver. We will be more levered than normal on closing of the acquisition, but the strong cash flows and earnings from our businesses will assist us in delevering over the next couple of years. As you know, we continue to evaluate the potential sale of a minority interest in our Colorado IPP facility, which may yield proceeds allowing us to reduce debt. And to help fund our strong future utility focused capital program, we plan to put an at the market equity program in place in 2016. We will prudently issue equity through that program in 2016 and 2017. We are committed to maintaining our current solid investment grade credit ratings and our forward forecasted metrics support those ratings. Slide 22 demonstrates our track record of growing operating earnings and EPS. We look forward to closing the SourceGas acquisition and taking the next step forward in continuing to build upon our impressive track record of growing shareholder value, as we serve our utility customer safely and reliably. Our strong forward utility-based capital program will drive an above average growth profile compared to our utility peers, and the addition of SourceGas will enhance our growth prospects. Moving to Slide 23, yesterday, we updated our 2016 EPS guidance to be in the range of $2.40 to $2.60. This revision updates our previous 2016 earnings guidance issued on November 23, taking into account the additional interest expense associated with our recent $550 million debt issuance. It’s important to note the range does not include any earnings contribution from the SourceGas properties. When the SourceGas transaction closes, we will issue updated 2016, guidance and preliminary 2017 guidance with refreshed assumptions for all our forward-looking activities. 2016 will be a busy year as we effectively manage our businesses, integrate SourceGas and position ourselves for strong earnings growth in 2017 and beyond. I’ll turn it back to Dave now for strategy update. David Emery All right. Thank you, Rich. Moving on to Slide 25, we’ve shown you this slide for quite sometime now. But we group our strategic goals into four major categories and really with the overall objective of being an industry leader in all we do. Those four key objectives are profitable growth, valued service, better everyday, and great workplace. In the profitable growth area on Slide 26, strong capital spending drives our earnings growth. And we forecast total of more than $1.1 billion in capital spending for 2016 through 2018. That projected spending far exceeds our depreciation driving the earnings growth. It’s important to note that this table on Slide 26 does not include any capital related to the SourceGas acquisition. Once that acquisitions close, we’ll provide some revisions to the forecasted capital spending. On Slide 27, we continue to make great progress constructing our new turbine at the Pueblo Airport Generating Station at $65 million simple cycle gas turbine is on schedule and we expect it to be in service by year end 2016. To-date, we’ve spent about $35 million of a total $65 million budget were projected to come in at or under budget. Construction is about 27% complete and notably, we’ve had no safety incidents to-date. On Slide 28, as I mentioned earlier, we received approval from the Colorado PUC in October to purchase the new Peak View Wind Project for our Colorado electric utility. The third-party developer expects to commence construction in the first quarter and achieve commercial operations by year end at which time we’ll take over the project. We have made almost $12 million in progress payments as of December 31. Moving on to Slide 29, as Rich mentioned, our electric utility has demonstrated solid earnings growth in 2015, and a big part of that was our industrial load growth. We’ve had strong industrial load growth in all three of our electric utilities during 2015, for an overall increase in industrial load of almost 15%. That growth has been from several different industrial customers, but the datacenter load growth particularly in Cheyenne Wyoming is the most notable driver of that growth. Slide 30, another significant growth opportunity we’re pursuing very actively is the utility cost of service gas supply program. We’ve been talking about this for well over a year now. Under a cost of service gas program, our direct investment in natural gas reserves will provide long-term price stability for our customers, while also providing opportunities for increased investment and earnings for shareholders truly a win-win scenario. We submitted cost of service gas regulatory filing this fall in six separate states. Hearing dates have now been set in all six of those states. And we’re currently in the process of evaluating producing properties and drilling prospects for inclusion in the program that includes our Mancos Shale gas properties in the Piceance Basin in Colorado, which we’re evaluating now that we’ve finished up our test drilling program there. We hope to finalize our cost of service gas program sometime before year end 2016. Moving on to Slide 31, oil and gas strategy, Rich referred to this a little bit earlier. But we previously announced our plan to transition our oil and gas business to primarily support cost of service gas within our utilities. That program will provide stable price, low-cost fuel to our utility customers. As noted earlier, we completed our 2014/2015 Mancos Shale gas drilling program and essentially helped us prove up the magnitude of the resource we have in the Southern Piceance Basin. As Rich noted, we dramatically reduced our planned oil and gas capital spending for 2016 and 2017. Current product prices just simply don’t support additional capital investment in oil and gas. And our plan for capital going forward is essentially putting our capital investment into our cost of service drilling program. We’ve reduced our staff and cut cost in order to reduce our ongoing O&M. And our professional staff at our oil and gas subsidiary is busy applying their expertise and knowledge to assist our utilities with execution of cost of service gas. Moving on to Slide 32, this slide just simply provides a well by well details for our Mancos drilling program. It includes all the wells we’ve drilled now from 2013 through 2015. As I said earlier, overall we are very pleased with the results of the program little better than we expected. Moving on to Slide 33, I mentioned earlier, our dividend increase, we continue to be very proud of our dividend track record. And this is now being our 46th consecutive year of dividend increases for shareholders that’s one of the longest strings in the utility industry, and a record we’re very proud of. Slide 34, Rich talked earlier about our solid investment-grade credit metrics. We do have a solid balance sheet and good investment-grade credit ratings. Long-term, we expect the SourceGas acquisition to be credit positive, adding substantial low-risk, predictable cash flows to our credit metrics. On Slide 35, it illustrates the focus we place every day on operational excellence and on being a great workplace. During 2015, our safety record and our electric reliability performance were both near the top of the industry, that’s something we strive for an essentially all we do. On Slide 36, this is our scorecard, again, our way of holding ourselves accountable to you, our shareholders. Every year, we set forth our key strategic goals and initiatives and literally check the box on progress as we proceed throughout the year. Slide 36 is our 2015 goals and progress we’ve made towards those goals. Slide 37 is a preliminary scorecard for 2016. This includes the goal of completing the SourceGas transaction, but does not include any specific goals related to SourceGas. Once we require those properties, we will update the scorecard. That concludes our remarks. We would be happy to entertain any questions that anyone might have. Question-and-Answer Session Operator Ladies and gentlemen, we are ready to open the lines for your questions. [Operator Instructions] And your first question comes from the line of Insoo Kim with RBC Capital Markets. Please go ahead. Insoo Kim Hey, good morning, everyone. David Emery Hey, good morning, Insoo. Insoo Kim First question on the oil and gas strategy. I know you’ve talked about the low commodity price environment, and how the potential sale or divesting of the non – some of the assets would not result in the value that the asset that you don’t have. Just given the ongoing cost of service gas program, if that doesn’t go through, what are your thoughts regarding that business and the timing of such a strategic decision? David Emery Well, I think we have a pretty degree of confidence that we will have our cost of service gas program, the specifics of the size and which states choose to participate and at which levels, I think is the primary question in our mind, we think it’s a program that makes tremendous sense for customers and shareholders alike. And I think we’re uniquely positioned for that program because of our oil and gas expertise. Strategically, we’ve talked about divesting our non-core properties there. We’ve made the statement that we don’t intend a fire sale those if you will. But we are taking our time and making sure we can divest of those in a way that makes sense for us, and really focusing almost all of our attention on cost of service gas, whether that’s our Manco’s program and the shale gas resource we have in the southern Piceance Basin, or whether that would be reserves that we could potentially go out and purchase or a combination of the two, that’s really what we’re working on right now. We can’t finalize any of those plans or decisions until we know what size program we will have going forward, which of course is dependent on the regulatory process. Insoo Kim Got it. And sticking to cost of service gas, the CapEx estimates that you guys have through 2018 for that program. Is that still more of a placeholder for now, until you know what the details of the program are and the level of investments that you’ll be needing? David Emery Yes. Essentially, the way we came up with those numbers as we assume that we would commence a drilling program kind of late in 2016. We’ve talked about kind of our rough ongoing run rate for horizontal drilling program is around a $100 million for a rig running continuously for a full-year. And so that’s really where those numbers came from. We’ve got some wells, we have yet to complete in the Piceance and so the 2016 number is a little lower and then we basically assume a drilling rig year, if you will, for both 2017 and 2018, which I think is a pretty realistic assumption assuming we get the program off the ground. Insoo Kim Got it. And turning to the utilities business, for the legacy Black Hills utilities, ex-SourceGas, I guess beyond 2016 timeframe, what are some of the projects that you are looking for that could drive – further drive rate-based growth? David Emery Well, we’ve got several things we’re working on. In our slide deck, we do list a list – listing of kind of major utility projects. We break those out back in the appendix. And there’s several transmission projects, natural gas pipeline project, and other things that we’re actively pursuing right now. The other thing that we’ve talked about is, we’re short resources on the generation side and we talked about that in our Analyst Day back in October. We’re just getting started really on revisiting our resource planning for our electric utilities and fully expect that out of that, we’re going to need some additional resources to meet the load growth that we’re experiencing. Insoo Kim Got it. And just last question on – for the electric utility or I guess the electric or gas utility rate load growth, how much of your load growth is dependent on oil and gas customers? I’m assuming it’s relatively small, but – and what kind of impact have you seen, if at all, due to the low commodity price environment? David Emery Yes, essentially none of our load growth is dependent on oil and gas a very, very small percent. We don’t serve on the electric side direct oil and gas producing basins. So we get a small amount of kind of peripheral businesses that are located near the producing basins, but it really doesn’t drive a lot of growth a little bit and very light industrial and commercial load that we have – we do have one oil field that we serve at Black Hills Power had a little bit of load growth there it’s an enhanced oil recovery project. And I would say the prices there on a marginal cost basis are sufficient to keep producing. And so we really haven’t seen any cut backs in production, which would impact our load there. So a pretty minimal overall exposure to oil and gas prices on the electric utility side. Insoo Kim Got it. okay, thank you very much. David Emery You bet. Thank you. Operator Thank you. [Operator Instructions] Our next question comes from the line of Chris Ellinghaus with WillCap. Your line is open. Chris Ellinghaus Hey, guys, how are you? David Emery Good. Good morning, Chris. Chris Ellinghaus You quoted a $0.13 drag from weather for the year, I assume that’s versus 2014? David Emery No, that’s versus normal weather, Chris. Chris Ellinghaus Okay, great. David Emery And actually a little bigger than that compared to 2014, because 2014 was a little colder than normal. Chris Ellinghaus Okay. And can you give us any kind of characterization of how January went for the service areas? David Emery That are pretty close, but normal weather maybe slightly warmer than normal depending on the territory. Chris Ellinghaus Okay. And can you give us a little more detail on where the industrial strength is coming from? David Emery Yes, we’ve got several things, I mean, a lot of it is related to data center load growth in Cheyenne and Wyoming and then that’s the over warming portion of it. Colorado, some of our industrial businesses there have been growing at a steady clip, particularly gold mining has been real strong. There’s also an old munitions depot down in Pueblo, where they’ve ramped up load as they dispose of old weapons, and expect to keep that higher load for multiple years as they go through that process. Black Hills Power, we’ve just seen some of our industrial customers, whether that’s crude oil refining, I mentioned the oilfield earlier a combination of several of those things have helped expand load at Black Hills Power as well. Chris Ellinghaus Okay. And can you give us some ideas about when your next IRPs will get filed? David Emery Probably going to be late this year, or early next year. Chris Ellinghaus For all? David Emery Yes. Chris Ellinghaus Okay. David Emery We typically do our research planning for Cheyenne Light and Black Hills Power jointly. We manage that as essentially a single load, they’re interconnected systems, and we combine our resource planning efforts for those two. Colorado Electric, of course, we do separately. Chris Ellinghaus Okay. And do you have any planned major outages for this year or next year? David Emery We don’t have anything, I don’t think there’s any real lengthy outages. The ones we do have planned are incorporated into our earnings guidance. Chris Ellinghaus Okay. And do you have any updated thoughts on the Colorado SourceGas approval situation? David Emery No, I think we’re pretty well positioned there. We were successful in reaching a settlement. Colorado has a process, where your settlement is reviewed by an Administrative Law Judge and then the Commission requires a little time to review the recommendation of the ALJ and issue its order. We don’t foresee any real problems there. We are just kind of going through the motions, if you will, waiting for the process to play itself out. Chris Ellinghaus Okay. Thanks for the color, guys. David Emery You bet. Thank you. Operator Thank you. And our next question comes from the line of Andy Levi with Avon Capital Advisors. Your line is open. Andy Levi Hi. Good morning. David Emery Good morning. Andy Levi How are you? David Emery Great. Thanks. Andy Levi Just two questions, maybe three. But just the first one just on the IPP sale process. Can you just give us a little more color on that kind of I guess, it’s taking a little bit longer than you thought, so just kind of what’s going on there, and when we may hear something from you on that? David Emery Yes, I don’t know if it’s really taking a whole lot longer than we thought it would. We knew announcing kind of pre-holidays is not an ideal time to get things done expeditiously. The process is going well, obviously, we’ve engaged an investment banker. We’re going through the bidding process. We’ve had very strong indication of interest from multiple bidders. When you we are kind of working our way through the process. And I didn’t say earlier, we still expect to make a decision sometime before the end of the first quarter. Andy Levi Okay. And any reason to think that a sale wouldn’t happen, or that’s probably unlikely? David Emery Yes, I think it just really comes down to value. As I said, so far, indications have been pretty strong. But when you get down into negotiating real specifics and details and selecting final bids, you never know until you’re done. But we’re certainly encouraged by what we see so far. Andy Levi Okay. And then on the oil and gas segment, I just wanted to kind of understand what we got left on the books. I mean, I guess you showed $209 million of book value right at the end of December. Is that correct on page 20, I think it is? David Emery Correct. Andy Levi Okay. David Emery Yes, so… Andy Levi Can you give us a breakdown on the $209 million kind of… David Emery Sure. Andy Levi …how much is commodity related and how much is kind of, I don’t know hardware or kind of steel and the ground type stuff? Richard Kinzley Yes, as I pointed out in the comments earlier $94 million of that’s our full cost pool. So it’s the wells that are in our pool. $68 million is in unevaluated properties, which includes some infrastructure. And then wells – Dave mentioned that we drilled for wells in the Piceance, but didn’t complete them. So they are in that pool. And then you’ve got the balance, which is roughly $40 million which is the other assets of the business. Andy Levi Okay. So just to understand the commodity exposure piece is, what would you estimate? So if you kind of take out the pipeline stuff and trucks and things like that, what do you…? Richard Kinzley Say $150 million or $160 million is what’s left on the books, roughly exposed. Andy Levi Okay, okay. And then I know you commented on it, but I don’t think I was listening too closely. How much of that $150 million are you trying to get into rate-based gas? Or is that – is it not that defined? Richard Kinzley Really not defined at this point as Dave, mentioned a bit ago we’re evaluating whether a purchase of a third-party property or our existing gas assets make sense for that Cost Of Service Gas program, and working through that with regulators. Andy Levi Okay. What was the thing on the third-party? I’m sorry? Richard Kinzley Well one of the things we’ve evaluated in a way to potentially jumpstart our program if you will is assuming we get approval for Cost Of Service Gas if we could find a gas producing property perhaps with a distressed buyer or distressed seller. We might have an opportunity to buy a property in addition to looking at some of our properties primarily just the Mancos property is the one of our own really is a good viable long-term gas resource in at least the couple of trillion cubic foot resource potentially as much as 8 and that’s the one property. We have, we think would be a great fit for Cost Of Service Gas. But we’re also looking and if we can opportunistically purchase reserves from other parties we would like to do that to contribute to the program as well. Andy Levi Okay. And then – and I lied about the three questions. But in your guidance that you gave for 2016, the temporary guidance without SourceGas, what’s the – how much is oil and gas? What’s the drag? Richard Kinzley Well we haven’t broken out segment guidance like that yet when we get the SourceGas deal closed we intend to issue updated 2016 guidance and preliminary 2017 guidance and we may provide a little more color at that point around. Well certainly we’re going to provide updated assumptions on all our forward-looking activity including oil and gas, but we may provide a little more color at that time. Andy Levi I mean I guess the kind of way I looked at it is – and I think we’ve probably discussed this in the past – is that you have this really good story at the utility; the IPP is good and stable, you sell a portion of that. And the coal – mine math coal obviously is stable as well. So you have this really good kind of growth story at the utilities, especially with SourceGas. And then you have this distraction of this oil and gas business, which I understand you’re trying to get into rate base, for no better way to put it. But if, for some reason, a majority of those assets or the rate-basing of gas doesn’t materialize for whatever reason, what’s the longer-term strategy on this? Is it just to kind of sell it, or to kind of continue on? Again, this is assuming that commodity prices stay where they are, which I have no idea where they are going. But just kind of what your thinking is on that, because you have written down the majority of it, but it is a distraction and is a drag on earnings, and then ultimately valuation. So, without that drag, let’s just say it’s $0.25 to $0.40. You can kind of do the dumb math on a P/E basis, and you’ll come up with a higher valuation for the stock? Richard Kinzley Yes, I talked about this a little bit earlier, but I mean I think we fully expect to have a Cost Of Service Gas program going forward. The size of that and which states choose to participate at what level of production every year is really the question that we think it makes great sense to have a program. We think that we’ll be able to convince the regulators of the benefits to customer of having a program. There are tremendous benefits for customers in implementing a program, so we’re pretty confident we will have a program. And as we’ve said our strategy is to utilize that business to support Cost Of Service Gas. We’ve essentially eliminated any capital spending related to non-cost of service gas oil and gas investment. We’ve cut our staff, we’ve cut our ongoing operating expenses, we have the professional staff focused on Cost Of Service Gas. And as far as the other non-core properties we’ll continue to look for opportunities to divest those. We’re not just throwing our hands up and dumping them, but we’re going to sell them as prudent carefully review properties and sell them to people who it make sense to sell them to and gradually clean up the non-core properties, if you will. As far as ongoing earnings and the impact of ongoing earnings, when you look at the amount we impaired in 2015, the drag on earnings is going to be dramatically less than 2016 than it was in 2015. Just because we wrote off almost $250 million of our pool, and we’re not spending additional capital. So a depletion will be lower and then as we mentioned the cost structure is lower, so the drag will not be anywhere near what it was in 2015 and 2016. Andy Levi So on a clean basis, absent the write-downs, how much was the drag in 2015? Richard Kinzley Well, operating loss you can see in a press release was $27 million. Andy Levi Okay. So $27 million. We’ll use, I don’t know, 51 million shares to try and keep it kind of where it’s at. That was about $0.53 a share, or something like that on the new share count, absent the dilution from the converts, right? Is that right? So is there any type of guidance you can kind of give us? Richard Kinzley We’ll give updated guidance when we get the SourceGas deal closed. But basically 240 to 260 incorporates the assumptions we put out on November 23 guidance, incorporates the full drag of the equity, converts, and interest associated with the debt we just placed, and it doesn’t count any income contribution from SourceGas. So it’s a temporary number. Certainly, when we get SourceGas closed, I would expect 2016 to be higher than that, and then we’ll issue updated assumptions at that time. Operator Thank you. Our next question comes from the line of Tim Winter with Gabelli & Co. Your line is open. Tim Winter Good morning and thanks for taking my question. I wondered on the 2016 guidance, I have two questions. One is, what are you guys assuming for the IPP plant? Is there any earnings in there? And then the second part is, can you give us any updated metrics on SourceGas, maybe rate-based, ROE, earnings, anything like that that maybe just ballpark ranges? Richard Kinzley Repeat the first part again, Tim, on the IPP? You repeat the first question on IPP. Tim Winter What’s the assumption in the 2016 guidance for the…? Richard Kinzley Right now I assume that we own it for the full- year. Tim Winter Okay. Richard Kinzley And then on the metrics for SourceGas, again, we’ll put some color on that when we get the deal closed. Tim Winter Okay, okay. Thank you. Operator Thank you. Our next question comes from the line of Tom Nowak with Advent Capital. Your line is open. And I’m showing no further questions at this time. I’d like to turn the call back to David Emery for any closing remarks. David Emery All right. Well, thank you, everyone, for your participation this morning. We appreciate your continued interest in Black Hills. Have a great rest of your day. Operator Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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New Jersey Resources’ (NJR) CEO Larry Downes on Q1 2016 Results – Earnings Call Transcript

Operator Good morning and welcome to the New Jersey Resources Corporation First Quarter 2016 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Dennis Puma, Investor Relations. Please go ahead. Dennis Puma Thank you, Gary. Good morning, everyone. Welcome to New Jersey Resources’ first quarter fiscal 2016 conference call and webcast. I am joined here today by Larry Downes, our Chairman and CEO, Pat Migliaccio, our Chief Financial Officer, as well as other members of our senior management team. As you know, certain statements in today’s call contain estimates and other forward-looking statements within the Private Securities Litigation Reform Act of 1995. We wish to caution listeners of this call that the assumptions forming the basis for forward-looking statements include many factors that are beyond NJR’s ability to control or estimate precisely, which could cause results to materially differ from the company’s expectations. A list of these items can be found, but is not limited to items in the forward-looking statements section of today’s news release filed on Form 8-K and in our most recent 10-K filed with the SEC. Both of these items can be found at sec.gov. NJR does not, by including the statement, assume any obligation to review or revise any particular forward-looking statement referenced herein in light of future events. I would also like to point out that there are slides accompanying today’s discussion, which are available on our website and were also filed on our Form 8-K this morning. With that said, I would like to turn the call over to our Chairman and CEO, Larry Downes. Larry? Larry Downes Thanks, Dennis. Good morning, everyone and thank you for joining us. For those of you who have seen our release this morning, you know that our first fiscal quarter performance was solid. As we begin this morning I want to remind everyone that during my presentation I’ll be discussing our future and I’ll be making forward-looking statements. Our actual results will be affected by many risk factors, including those that are listed on slide two. The complete list is included in our 10-K and as always I would encourage you to please review them carefully. Also as noted on slide three, I will be referring to certain non-GAAP measures such as net financial earnings, or NFE as I am discuss our results. We believe that NFE provides more complete understanding of our financial performance. However, I want to stress that NFE is not intended to be a substitute for GAAP. Our non-GAAP measures that are discussed more fully in Item 7 of our 10-K and please take the time to review that disclosure carefully as well. Moving to slide four, you can see our financial and strategic highlights for the quarter. NFE for the quarter were $0.58 per share compared with $0.65 per share in the first fiscal quarter 2015. The difference is due primarily to lower results at NJR Energy Services. Our fundamentals at New Jersey Natural Gas remained strong. We added 2,046 customers during the first fiscal quarter of 2016 and remain on track to realize a 1.6% customer growth rate during this fiscal year. We filed the base rate case in November to recover investment and operating cost incurred to improve our system and support customer growth initiatives. We also reached another important milestone during the quarter when we retired the last section of cast iron main in our distribution system. We are now the only utility in New Jersey to have a cast iron free system. Our infrastructure investment programs continued as expected. In the quarter New Jersey natural gas spent about $44 million for customer growth and to improve the reliability and resiliency of our system. Our clean energy ventures completed their third onshore wind project in December this 50.7 megawatt Alexander Wind Farm is located in Rush County, Kansas. We now have three operating wind farms that are contributing to our earnings and as you know we announced the fourth project last night. Also congress extended investment tax credits for solar and production tax credit to wind in December. That has positive implications for our distributed power business and although lower than last year NJR Energy Services is performing well despite the warm weather and their results remain in line with our expectations. Moving to slide five, this morning we announced net financial earnings of $49.6 million or $0.58 per share during the first fiscal quarter of 2016. That compared with $55.1 million or $0.65 per share last year. New Jersey Natural Gas reported strong earnings as a result of higher gross margin from customer growth, our BGSS incentives and regulatory initiatives such as the SAVEGREEN project. Although, the quarter was about 35% warmer than normal our Conservation Incentive Program, which we referred to CIP mitigated the impact on earnings. Our midstream, excuse me moving to slide six, our long-term average annual NFE growth rate remains 5% to 9% and that assumes that fiscal 2013 is the base. Today, we reaffirmed our NFE guidance for fiscal 2016 in the range of $1.55 to $1.65 per share. First and foremost I want to emphasize that the guidance assumes that New Jersey Natural Gas will remain the primary driver of our strategy and our performance. New Jersey Natural Gas will provide the majority of our earnings, our assets, our people and our capital investments. Infrastructure projects and new customer additions will continue to drive our investments. Our midstream investments will also contribute to our regulated earnings combined with New Jersey Natural Gas our regulated businesses are expected to contribute between 65% and 80% of total net financial earnings in fiscal 2016 and beyond. As I mentioned earlier, NJR clean energy ventures provide renewable electricity from our solar and wind investments. We are focused on diversifying our earnings through this business as we continue to grow our portfolio of wind projects. Clean energy ventures is expected to provide between 10% and 20% of net financial earnings in fiscal 2016 and beyond. Now I think as many of you recall extreme volatility in fiscal 2014 and 2015 created market opportunities that led to outstanding performance for NJR Energy Services. This year warm weather conditions created by El Niño patterns have resulted in less volatility than we experienced in the previous two fiscal years. And so we expect that NJRES will contribute between 5% and 15% of net financial earnings in fiscal 2016 and that number is consistent with our expectations. At the same time, our annual dividend growth goal remains at 6% to 8% with the targeted payout ratio of 60% to 65%. Turning to slide seven, in December, Congress extended both the production tax and investment tax credits essentially the legislation extended the PTC and its existing value of $23 per megawatt for wind projects that begin construction through December of 2016. The value of the PTC will gradually decline to 2019 and thereafter will be eliminated. In addition, the investment tax credit was extended at its current level of 30% for solar projects that commence construction before December 2019. The credit reduces to 26% for projects started in 2020 and to 22% in 2021 provided that these projects are in service by December of 2023. Commercial solar projects started after 2021 are eligible for a 10% ITC. And now I think as many of you know over the past several years, our strategy reflected our expectation that Congress would not extend these credits. As a result, our plan was to reduce our solar capital spending and to diversify our portfolio, which as we indicated on our Investor Day in October we were on track to achieve that. The ITC and PTC expenses now provide us with options to invest in wind and solar over the next several years and we are currently reviewing how these changes will impact our future CEV investments. In the short-term you can expect us to focus on the build out of our BPU approved grid connected solar projects in New Jersey to continue our residential solar program and to add onshore wind projects to our portfolio, but I would again emphasize that we continue to expect that CEV will contribute 10% to 20% of our NFE and that remains unchanged from previous forecast. On slide eight, last evening we announced our fourth onshore wind project a 39.9 megawatt Ringer Hill Wind project, which is located in Somerset County, Pennsylvania, that is about 60 miles from Pittsburgh. We’ll invest about $84 million in this project and we expect that we’ll come online during first quarter of fiscal 2017. When the Ringer Hill is completed we will have four wind farms with total capacity approximately 120 megawatts of renewable electricity. And before I turn the call over to Pat to discuss our quarter results, I want to review slide nine which summarizes our capital expenditure program, in the chart you can see that the majority of our capital investments will continue to be allocated to our regulated utility New Jersey Natural Gas and our midstream businesses. And so I will turn the call over to Pat who will review our financial results, but I want to remind everyone that Pat officially became our Chief Financial Officer effective January 1st so this is his first opportunity to share our financial results with you. But Glenn is in the room and he’ll keep an eye on Pat so not to worry. Pat? Patrick Migliaccio Thanks, Larry and good morning, everyone. As you can see on slide 10 NJNG’s net financial earnings were $30.6 million compared to $28.2 million in the prior quarter. The improved financial performance was driven by a significant increase in gross margin from customer growth, our BGSS incentive programs, and SAVEGREEN our energy efficiency program. Since this inception the BGSS incentive programs have saved customers approximately $800 million and also provided share owners at an average of $0.05 of NFE per share annually. Turning to Slide 11, we added 2,046 new customers in the first quarter with approximately half of those customers coming from other fuels, primarily fuel oil. Combined these new and conversion customers are expect to contribute approximately $4.4 million annually to utility gross margin. Although additions are down in the first quarter due to the timing differences we’re on track for the year and expect to add 8,150 customers to our system in fiscal 2016. This will be about 4% increase over the prior year. Through our fiscal year 2018 we expect customer growth additions of 24,000 to 28,000, representing an annual new customer growth rate of about 1.6%. Most of you are familiar with the regulatory programs that we list on slide 12. I just mentioned the impact that our BGSS incentives have had in the results, our CIP which has been in place for about 10 years significantly mitigated the impact of warm weather and a resulting lower usage levels in our first quarter. This past November-December were among the warmest in our company history. Through SAVEGREEN we invested $8.6 million in the first quarter 2016 and our VP approval to invest $220 million through June of 2017. This program supports New Jersey’s energy efficiency goals by helping both customers and share owners. Also in the first quarter we invested $7.2 million in SAFE program. SAFE is $130 million four-year infrastructure program to replace 276 miles of unprotected steel and cast iron main to ensure safety and reliability. And finally we invested $5.1 million during the quarter in our NJ RISE program, which is $102.5 million five year program consisting of six capital projects designed to improve the resiliency of our system. As Larry has mentioned we filed our base rate case on November 13th as the BPU questioned when they approved our SAFE infrastructure program in 2012. The $147.6 million rate increase request will primarily allow us to recover cost incurred to improve our system and support customer growth. As you can see we have included the details of our forecasted rate base and cost of capital on the slide. We’re currently in a discovery phase. The BPU rate case process can take up to 12 months so we expect to have new rates in the first fiscal quarter of 2017. Moving to slide 14, midstream NFE totaled $2.3 million in the first quarter of 2016 compared with $2.1 million in the prior year. The increase reflects higher revenue from the Steckman Ridge storage facility. We also have a 20% interest in the PennEast Pipeline, which filed its 7C application with FERC in September and we’re currently working through the approval process. There is contribution from NJR Midstream in fiscal 2016 is expected to remain at 5% to 10%. Turning to slide 15, Larry mentioned earlier that NJRES reported lower NFE of $10 million in the first quarter of 2016, compared with $16.4 million last year. As expected their financial margin was lower than last year due primarily to narrow price spreads resulting from lower natural gas prices. And as Larry mentioned, we expect NJRES to contribute 5% to 15% NFE in fiscal 2016 and beyond. Moving to slide 16, first quarter 2016 NFE at NJR clean energy ventures totaled $7.5 million compared with $9 million last year. The decrease quarter-over-quarter was due primarily to lower investment tax credits. Our Sunlight Advantage program added 84 residential customers or 0.7 megawatts in the first quarter. This brings the total number of residential customers to more than 4,000 and our residential solar portfolio to more than 36 megawatts. Total capacity for all LCV solar projects is now just over 118 megawatts, which produces approximately 142,000 SRECs annually. Adding new three wind projects to that total, our distributed power portfolio is nearly 199 megawatts of which approximately 40% is wind. As shown on slide 17, we’ve been actively hedging our SREC sales. When considering our expected generation, we are 92% hedged for fiscal 2016 as you can see from the chart and we’ve been actively hedging future years. The red line represents the SRECs we expect to be generated from our existing portfolio. We believe that the increasing number of SRECs, the expectation of continued strength in SREC prices, the impact of our hedging program and expected earnings from our wind investments, support our forecast of 10% to 20% of our total NFE coming from CEV in fiscal 2016 and beyond. I will now turn the call back to Larry, for his closing comments. Larry Downes Thanks, Pat. I want to conclude our call today with a review of our path to future growth which includes a summary of our key initiatives for fiscal 2016, ‘17 and ‘18. I think many of you may recall that the format on slide 18 was originally introduced at our 2014 investor conference and really what it’s designed to do is to summarize the key initiatives each year that support our annual 5% to 9% NFE and 6% to 8% dividend growth target. And so when you look at the slide you will see details for fiscal 2016 and then as you move into fiscal ‘17 and ‘18 you will see it will be the initiatives from ‘16 plus the additional initiatives that you see in ‘17 and ‘18. So I just want to take a moment to summarize that. The growth plan through fiscal ‘18 is based upon strong customer growth, infrastructure investments, regulatory initiatives at New Jersey Natural Gas that will benefit both customers and share owners. We continue to work collaboratively with our regulators on our initiatives that benefit not only our share owners, but also our customers. We also expect to benefit from consistent revenues from our midstream investments; we’re focusing on diversifying CEVs distributed power portfolio combined with improvements in the SREC market fundamentals and the extension in both investment tax credits and production tax credits. And finally we will continue to take advantage of expected natural gas demand growth and price volatility at NJR Energy Services while at the same time providing producer an asset management services. When we look at our strategy, and we look at our fundamentals they remain strong and we think they provide the opportunities for future growth. But as always as I close I want to say thank you to our nearly 1,000 employees for their continued dedication and commitment to our company and our customers. Without their efforts we would not have achieved the excellent results we reported this morning, without everything that they do every day we would not have the strong fundamentals that we have for the future. Our employees are the foundation of our company and I am grateful for what they do every day. So, thank you for your time today and we are ready to take your questions and comments. Question-and-Answer Session Operator We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Mark Barnett with Morningstar. Please go ahead. Mark Barnett Hey, good morning everybody. Larry Downes Good morning, Mark. Mark Barnett Congratulations Pat and Glenn first of all get that out of the way. Patrick Migliaccio Thank you, Mark. Dennis Puma Thank you. Mark Barnett Just a couple of quick things here, one on the just the minor item on the rate case, but you had a number of ways to kind of generate incentive extra margin from the utility. Do you think that any of that is set to change following a new rate regime or should we generally be expecting about a steady performance there? Larry Downes Mark, we don’t expect any of that to change. Mark Sperduto was in the room. Do you want to add anything to that? Mark R. Sperduto No, I think what you might be referring to are the BGSS incentives as well as our CIP. Those two regulatory initiatives have been decided and they are continuing right through the right case without any change. There are recent decisions in both of those areas. Mark Barnett Right. I just kind of from a bigger picture just wanted to get your sense of how that would change with a new fixed rate. But that sounds like no problem there. Couple of quick questions on the Ringer Hill projects, you mentioned that it was hedged for 15 years with an industrial uptick or so two things, one, generally how fixed do you view the revenue contribution from that project? And then two, how do you view your own sort of cost of capital and hurdle rate with an industrial offtake or versus a utility offtake there? Larry Downes Mark can we ask Pat to respond to that and we also have with us Stan Kosierowski who heads up CEV. So they will take your question. Pat? Patrick Migliaccio Good morning, Mark. So we hedged the majority of the output on that project. The Ringer Hill project through that agreement. And so while we didn’t disclosed a specific number rest assured the majority of the power is hedged. In terms of the cost of capital assumptions relative to the industrial partner the counter party choose not to be named on our press release, industrial partner was as close as we could come to describing their line of business. But we don’t consider the credit quality of the counter party in our return calculations and there are credit protections in the agreements with the counter party. So the credit quality deteriorated. I don’t know if Stan has anything to add. Mark Barnett Okay. Just this is sort of a growing trend with some of the more distributed generations I was just curious to see your kind of framework for analyzing this kind of a project when your offtake was not sort of fully regulated utility. But appreciate that guys. Thanks. Operator The next question comes from Brian Russo with Ladenburg Thalmann. Please go ahead. Brian Russo Hi, good morning. Larry Downes Good morning, Brian. Brian Russo So just to clarify the wind farm announced last night that was assumed in your capital forecast, CapEx forecast, correct? Patrick Migliaccio Yeah, Brian. This is Pat Migliaccio. That’s correct. Brian Russo Okay. And with the PGC and ITC extension clearly there is upside opportunities and upside CapEx opportunity. How much incremental CapEx do you think you can handle without needing significant amount of equity to funding? Larry Downes Brian, this is Larry. I think at this point what we are doing is as you know just as I said we had really assumed that we would not have the ITC and the PTC and that with the CapEx numbers that we were putting out there in the forecast. Now that this is in place what we’ll be doing is a complete let’s see at the portfolio and the distribution between wind and solar. There may be some changes there, but what will not change is the 10% to 20%. Brian Russo Got you, okay. And the SREC hedges slide and average price it looks like the hedges percentage basis increased and so did the average prices maybe you could just talk a little bit more about what you are seeing in that market in terms of pricing et cetera? Patrick Migliaccio Sure Brian. This is Pat Migliaccio again. We’ve seen over the course of the last several weeks certainly strengthen in the SREC market reflecting the BGS auctions and the purchasing behavior that leads up to the BGS options in the state of New Jersey. So to put things in perspective energy years ‘16 and ‘17 are trading in a bid ask between say 285 and 295 over the course of the last several weeks. So as you might imagine we’ve been aggressively hedging given those market prices. Because they are near 90% of the SACP, which is the penalty rate the PLSCs pay if they don’t acquire those SRECs. Larry Downes Brian we also and we guided to this in a lot of detail at the October Investor Meeting. We spend a lot of time internally understanding the market and where it is relative to the renewable portfolio standards. So as we said our expectation was that there would be some improvement in the SREC market fundamentals and we’re seeing a little bit of that right now. But internally when we’re making our hedging decisions we’re not looking take an enormous [ph] amount of risk on the movement of SREC prices and you can see that reflected in some of the hedging strategies and decisions that we’ve made. Brian Russo Okay. And you mentioned PennEast the FERC filing is it still considered on schedule? Larry Downes Yeah as we’ve disclosed right now, we’re going through the FERC process and expecting to get the FERC certificate. So there is no change to the schedule right now. Brian Russo And then lastly with the decline in natural gas, what kind of offset do you think there is to the $147 million base rate increase, which on a percentage basis is fairly large? Larry Downes I’m going to ask Mark Sperduto to talk about that. Mark R. Sperduto Well the system that for gas cost each June and coming up in this June we’ll do a forecast of our gas cost. And that forecast will coincide approximately with the timing of our base rate case increase. So until that time, as mentioned gas prices have been historically low and those types of prices would be reflected contemporaneously with the change in our base rate case increase this coming October-November timeframe. Larry Downes So Brian I think at this point it’s impossible to really predict that with the specificity right now. Brian Russo Okay. And then lastly I noticed midstream first quarter ‘16 was up year-over-year, but yet you sold Iroquois. I think you mentioned Steckman Ridge growth. Maybe you could just add a little bit more color to that. Larry Downes Yeah Brian, Pat gave without – Steckman Ridge provided – more than offset the decline of revenue that we saw from the difference in dividend income on our Dominion Midstream units versus the income from Iroquois and principally the same fundamentals that we see that drive the solid performance of NJRS are driving the performance of Steckman Ridge. So you’ve got some spreads in the Marcellus area that are leading to higher hub services and storage revenue at least in the short-term in Steckman Ridge. Brian Russo Great, thank you. Larry Downes Yeah. Operator [Operator Instructions] As there are no further questions, this concludes our question-and-answer session. I would like to turn the conference back over to Dennis Puma for any closing remarks. Dennis Puma Thank you, Gary. I want to thank everyone for joining us again today. As a reminder, a recording of the call is available for replay on our website. Again we appreciate your interest and investment in New Jersey Resources. Thanks have a great day. Bye. Operator The conference is now concluded. Thank you for attending today’s presentation. You may 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.) 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