Black Hills Corporation’s (BKH) CEO David Emery on Q1 2016 Results – Earnings Call Transcript
Black Hills Corporation (NYSE: BKH ) Q1 2016 Earnings Conference Call May 04, 2016 11:00 AM ET Executives Jerome Nichols – Director, IR David Emery – Chairman and CEO Rich Kinzley – SVP and CFO Analysts Insoo Kim – RBC Chris Ellinghaus – The Williams Capital Group Lasan Johong – Auvila Research Consulting Operator Good day ladies and gentlemen, and welcome to the Black Hills Corporation’s First Quarter 2016 Earnings Conference Call. My name is Andrew, 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 go ahead sir. Jerome Nichols Thank you, Andrew. Good morning everyone. Welcome to Black Hills Corporation’s first quarter 2016 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. Before we begin today, I would like to note that Black Hills will be attending the American Gas Association Financial Forum next week in Naples, Florida. Our presentation materials and webcast information will be posted on our website at www.blackhillscorp.com under the investor relations heading. 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 two of the investor presentation on our website and our most recent Form 10-Q and Form 10-K 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. Good morning, everyone. Thanks for being with us this morning. For those of you following along on the webcast slide deck, I will be starting on slide 3. We will follow a similar agenda to what we’ve done in previous quarters. I will give a quick overview of the quarter. Rich Kinzley, our CFO will cover the financial highlights for the quarter. I will visit briefly about strategic forward issues and then we will take questions. Moving to slide 4, with the closing of the SourceGas acquisition we’ve largely completed our nearly 12 year transition to a pure-play utility company. We now serve more than 1.2 million customers in eight states, and our utility operations account for the large majority of our earnings, assets and employees. In addition, all of our non-utility businesses either support directly or are being transitioned to provide support directly to our own utility business. As a result and effective this quarter, we made some changes to the way we will now report operating and financial results going forward. Those changes have also been made to previous periods to allow for direct comparisons. Most notably we won’t continue to report by our two major business groups, Utilities and Non-Regulated Energy. Rather we’ll simply have five reporting segments, those are the Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. We’ll also report Cheyenne Light’s gas distribution results within our Gas Utilities business segment. They were previously reported within the Electric Utilities segment. And then finally, we recently rebranded all of our utilities under the name Black Hills Energy. That’s a name we’ve used since 2008 for many of our utility properties, and we’ve just finished that process with SourceGas and then our two legacy utilities, Cheyenne Light and Black Hills Power. All have been renamed Black Hills Energy. We included a table in both the earnings press release and in the appendix of the webcast presentation that outlines our various utility, subsidiaries, their legal names, and then how we intend to refer to those in our investor materials going forward. So with that, I will move onto slide 6, first quarter highlights. We had a strong first quarter, especially when you consider the mild winter weather that we had, and continued weak oil and gas prices and of course the massive effort that’s has gone into closing and integrating SourceGas. Talking about highlights for the utilities, obviously the most notable one is the fact that we closed the purchase of SourceGas on February 12. That acquisition for $1.89 billion added about 429,000 utility customers in Arkansas, Colorado, Nebraska and Wyoming. Three of those states we already do business in, and of course Arkansas is a new state for our utility operations. Given the February 12 close, obviously financial results have been included for SourceGas from February 12 through March 31, so about half of the quarter. During the quarter, we continued construction on our $65 million, 40 megawatt national gas turbine at the Pueblo Airport Generating Station. That project is on schedule to be completed and placed in service before year end. We filed a request yesterday with the Colorado PUC to increase annual revenue to recover our investments and expenses associated with the new turbine. Construction also commenced during the quarter on the new $109 million, 60 megawatt, Peak View Wind Project also for Colorado Electric, and also expected to be in service by year end. Our South Dakota Electric Utility subsidiary commenced construction on the first segment of a new 144 mile $54 million electric transmission line that will go from Northeast Wyoming to Rapid City, South Dakota. We expect that line to be in service in the third quarter, and then our cost [facility] gas hearings are underway actually this week in the state of Nebraska, and they are set for Iowa, Kansas, South Dakota and Wyoming over the course of the next few months. On April 27, the Colorado PUC dismissed our cost of service gas filing in Colorado without prejudice. In order to provide a little clarity around that decision, I think it’s important to understand that when we filed our regulatory applications for cost of service gas in all six of our states, we proposed that approvals be done in two separate phases. Phase 1 would establish the basic regulatory construct for the program, and phase 2 would provide approval of specific gas reserve properties for inclusion in the program and the associated impact on customers’ cost of gas. Specific to Colorado, although we have not yet received a written order, the Commissioner seemed to indicate a preference for combining the two phases into a single proceeding. So just to be clear, a phase 1 approval will not impact customer rates. It will simply establish the financial and other criteria we need to select properties for inclusion in the program. The phase 2 process will provide approval to include specific gas properties and the associated customer impacts. Now in Colorado, once we receive the Commission’s written order, we will evaluate our options and determine how best to proceed. That may include re-filing with a specific property for Colorado PUC approval and inclusion in the program. Moving on to slide 7, the first quarter highlights continued, our Power Generation segment closed the sale on April 14 of a minority interest in Colorado IPP’s 200 megawatt power plant for $215 million. The proceeds were used to reduce debt. Our Oil and Gas financial results were negatively impacted by continued low oil and natural gas prices during the quarter. On the Corporate front, we reached an agreement with IRS appeals regarding disputed items for prior tax years going all of the way back to 2007, resulting in about $5.1 million of tax benefits. And I will let Rich explain those in a little more detail, when he goes over the financial statements. We declared a quarterly dividend of $0.42 per share, and in March we implemented an at-the-market equity program to sell shares of common stock. On slide eight, the SourceGas integration is going very well. We expect to largely complete all of that activity by the end of the year. Now that’s a very aggressive but also a very achievable goal and we are making great progress. A lot of activity has already been completed or is well underway. The most notable item is, we’ve completed the conversion of our human resources and payroll systems, completed the conversion of our financial systems, a lot of our rebranding activity at least associated with vehicles and uniforms and things have been completed, and we’ve also made a lot of organizational and staffing decisions related to the integration and that’s all well underway. Key items remaining in the year, the largest of which is our customer information system conversion; we expect that to be done in the fall and along with that then we would integrate our bill, print and payment processing along with the change in customer information system. On slide 9, we have a graphical representation of integration progress through April 15. It’s broken into five major categories as well as an overall progress report. As you can see, we are making excellent progress on all fronts there. Slide 10; provide highlights regarding our sale of the minority interest in our Black Hills Colorado IPP assets. As I said earlier, we did close that transaction on April 14, generating about $215 million in proceeds. We will continue as the majority owner of that facility and will continue to operate it. There will be no impact to the customers as a result of the transaction. The market conditions related to the sale of this asset really provided a unique opportunity for us to capture tremendous value for shareholders. Slide 11 just provides a reconciliation of our first quarter income from continuing operations as adjusted, compared to the first quarter of last year in 2015. As you can see, we showed some great improvement across many of our business segments with gas utilities demonstrating the largest increase of course due to the addition of the SourceGas property in mid-quarter. That concludes my comments for now. I will turn it over to Rich to cover the financial highlights. Rich? Rich Kinzley Thanks, Dave. Good morning everyone. As Dave indicated, it was a busy first quarter. We’re pleased we closed the SourceGas acquisition on February 12, ahead of expected timing, which allowed us to pick up part of the heating season from those gas utilities. Integration activities around the SourceGas acquisition are progressing as planned as Dave noted, and despite mild weather in the first quarter, we are pleased with our operating results. On slide 13, we reconcile GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings that better represent our ongoing operating performance. This slide displays the last five quarters and trailing 12 month as of March 31 for each 2016 and 2015. During each of the past four quarters, we incurred significant acquisition expenses related to SourceGas such as advisory fees and financing and other third party costs. We also incurred non-cash ceiling test impairment charges at our Oil and Gas business in each of the past five quarters, due to continued low crude oil and natural gas prices. The acquisition expenses and impairments are not indicative of our ongoing performance, and accordingly we reflect them on and as adjusted basis. Our first quarter as adjusted EPS was $1.23 per share compared to $1.08 per share in the first quarter last year. Comparing Q1 2016 to Q1 2015 at a high level result in 2016 benefited from a partial quarter ownership of the SourceGas Utilities and corporate tax benefits. These positive items were partially offset by increased share count from our November equity issuance, higher interest expense from higher debt balances and milder weather. I’ll detail these items in the following slides. Trailing 12 months as adjusted EPS increased by 7.5% to $3.14 per share. Slide 14 displays our first quarter revenue and operating income. On the left side of the slide, you will note that revenue was only slightly higher in 2016, despite the addition of SourceGas. This is due to reduced revenues at our Gas Utilities from lower pass-through gas costs during the period, given the low natural gas price environment and milder winter weather. On the right side of the slide, you see a 21% increase in total operating income, driven by a $22 million increase at our gas utilities. $21 million of this increase came from 49 days ownership of SourceGas. Power Generation delivered strong performance in the quarter, while our Electric Utilities and Mining segments were flat year-over-year. Despite lower revenue due to lower received crude oil and natural gas prices, Oil and Gas’s operating loss was lower in 2016 driven by lower G&A and lower depletion. The Corporate segment operating loss of $5.4 million was driven by internal labor costs, which supported our SourceGas integration efforts. Excluding the positive impact of the SourceGas acquisition, consolidated operating income in the first quarter of 2016 was essentially flat, compared to 2015 mainly due to milder weather in 2016. Side 15 displays our first quarter income statement. Gross margin, operating expenses and DD&A all increased comparing 2016 to 2015, as a result of the SourceGas acquisition. As I noted on the previous slide, operating income before special items increased by 21% year-over-year. Special items included the Oil and Gas ceiling test impairment and acquisition related costs including bridge financing costs through February 12, when we closed the acquisition. These items amount to $39 million pretax in 2016 or $0.46 per share. Interest expense increased year-over-year related to increased debt associated with the acquisition. You will note we had a very low effective tax rate for the quarter in 2016. This is due to two items; first, during the quarter, we reached agreement with the IRS on disputed items for the tax years 2007 through 2009, resulting in tax benefits of $5.1 million. Second, we changed our methodology for tax depletion at our Oil and Gas subsidiary, during the quarter resulting in a tax benefit of $5.8 million at the Oil and Gas segment. This includes benefits for the years 2007 through 2014 for this change an estimate. Together these tax items amounted to approximately $0.20 of EPS. We did not characterize these items as special adjustments since we accrued tax related to each of them in as adjusted earnings in previous years. Finally, you’ll see the 7.2 million diluted share outstanding increase from the previous year resulting primarily from our equity end unit mandatory issuances in November of last year related to the acquisition. We issued 6.3 million common shares in November and the application of the treasury stock method related to the unit mandatories added approximately 720,000 shares in the quarter. Additionally, we sold 261,000 shares through our at-the-market program as Dave mentioned. That was done the last few days of March; 140,000 of those shares had settled at March 31. For the quarter, as adjusted EPS grew 14% year-over-year, while as adjusted EBITDA increased by nearly 20%. The left side of slide 16 displays our Electric Utilities gross margin and operating income. Comparing 2016 to 2015, gross margin decreased by $1.2 million and operating income decreased by $300,000. Gross margin decreased primarily due to a Q1 2015 $2.1 million one-time settlement with the Colorado PUC on the renewable energy standard adjustment related to our Busch Ranch Wind Farm. This was partially offset by increased writer CapEx related revenue in 2016 and the benefit of an additional day of margin in 2016 due to Leap Year. Weather had a nominal impact on gross margin year-over-year at the Electric Utilities. O&M at the Electric Utilities was $1.9 million lower in the first quarter of 2016 compared to 2015, driven by the increased allocation of central service cost to corporate in 2016 related to SourceGas integration activities. Comparing 2016 to 2015 at our Gas Utilities on the right side of slide 16, gross margin increased by $45 million and operating income increased by $22 million. The gross margin increase was driven by the partial quarter ownership of the SourceGas Utilities, which added 46 million. Gross margin in 2016 also benefited by 1.8 million from our prior year Wyoming acquisitions. Unfavorable weather decreased gross margin at our legacy Black Hills Gas Utilities by 2.8 million, with 23% fewer heating degree days in Q1 2016 compared to Q1 2015. O&M at the Gas Utilities increased by 14.5 million year-over-year, 18 million of this increase is attributable to the addition of SourceGas. The increase in O&M was partially offset by the increased allocation of central service costs to corporate in 2016 related to SourceGas integration activities. Depreciation at the Gas Utilities increased 8.2 million in 2016, primarily due to the addition of the SourceGas assets, which added 7.1 million. Quantifying the impact of weather on our results in Q1 2016 compared to normal, heating degree days at our Gas Utilities including the partial quarter ownership of SourceGas were 11% below normal, negatively impacting gross margins by an estimated $4.6 million. Also, heating degree days at our Electric Utilities were 12% below normal, negatively impacting gross margins by an estimated 1.5 million. Combined, the mild weather compared to normal negatively impacted our EPS by approximately $0.08 in Q1 2016. On slide 17, you will see that Power Gen improved operating income by $900,000 for the first quarter compared to 2015. The main driver in improved operating income was annual increases in power purchase price agreements. O&M and depreciation were comparable to the prior year. Moving to the right, our Mining segment had $100,000 operating income decrease compared to the first quarter of 2015. Year-over-year revenue was $400,000 higher and O&M was $500,000 higher. O&M increased due to our move into higher overburdened areas of this mine. Our cost plus contracts on 50% of our production allowed us to recoup part of the higher mining costs, explaining the bulk of the revenue increase. Moving to Oil and Gas on slide 18, we incurred an operating loss in Q1 2016 of 4.8 million excluding a $14 million pretax ceiling test impairment charge, compared to an operating loss of 7.2 million in Q1 2015 excluding a 22 million pretax ceiling test impairment charge. First quarter production increased 6% from 2015, driven by a 21% increase in oil sales volume, which resulted from wells drilled in late 2014, early 2015. From an average price received standpoint including hedges, crude oil decreased by 28% and natural gas decreased by 41%, comparing Q1 2016 to Q1 2015. These lower received prices resulted in a revenue decrease of 2.9 million year-over-year. O&M decreased by 1.9 million in Q1 2016, as we’ve diligently managed our cost structure at Oil and Gas. The impairments taken in 2015 and 2016 have driven down our depletion rate lowering DD&A by 3.4 million comparing Q1 2016 to Q1 2015. We are actively transitioning our Oil and Gas business to support our utility cost of service gas initiative, and we are opportunistically evaluating divestitures of properties that do not support that initiative. On slide 19, you see a review of how we paid for the SourceGas acquisition. As I mentioned earlier, last November we issued 6.3 million shares of common stock for net proceeds of $246 million and concurrently we did a unit mandatory issuance for $290 million of net proceeds. In January, we completed a $550 million debt offering ahead of the closing of the acquisition on February 12. At closing on February 12, we assumed 760 million of SourceGas debt, and drew on our revolver for the remaining needed proceeds to cover the $1.89 billion purchase price. This mix of debt and equity to fund the acquisition levered our balance sheet, which brings me to slide 20. At the end of Q1, our net debt-to-capitalization ratio was 69.2%. This is higher than normal and resulted from three things. First, the SourceGas acquisition was funded mostly with debt as I just explained. Second, the $299 million of unit mandatories are reflected as debt on our balance sheet until they convert to equity in 2018. And third, the after tax non-cash ceiling test impairments we’ve taken over the past five quarters have reduced equity by over $170 million. We are focused on de-levering the balance sheet over the next couple of years. We began the process in March by issuing shares through our new at-the-market equity offering program, which we expect to continue through 2016 and into 2017. As Dave mentioned in April, we completed the sale of a minority interest in our Colorado IPP facility and received $215 million, a large portion of which were used to reduce debt in the second quarter. Looking ahead at the strong cash flows and earnings from our businesses, combined with the at-the-market equity program will support our dividend and strong utility focused capital deployment program, while assisting us with de-levering over the next couple of years. We are committed to maintaining our solid investment grade credit ratings and our forward forecasted metrics to support those ratings. All three rating agencies affirmed their ratings of Black Hills in February following the closure of the SourceGas acquisition. Slide 21 lays out our planned near term treasury activity, and slide 22 shows our debt maturity schedule. We are evaluating upsizing our $500 million revolver and initiating a related commercial paper program. We will continue to prudently utilize the at-the-market equity program in 2016 and 2017, and we have nearly 1 billion of debt coming due by mid-2017. The blue bars on slide 22 represent the SourceGas debt we assumed at closing, and provide us with an opportunity to improve on the associated terms given our higher credit ratings compared to SourceGas before the acquisition. We are evaluating refinancing alternatives and plan to refinance much or all of the upcoming maturities later in 2016 or early in 2017. Slide 23 demonstrates our strong track record of growing operating income and EPS. We are making excellent progress integrating SourceGas, and will have the majority of that work done by the end of 2016. We look forward to continuing to build upon our impressive track record of growing shareholder value as we serve our utility customers safely and reliably. Looking ahead, the synergistic qualities of the SourceGas acquisition and our strong utility based capital program will continue to drive an above average growth profile, compared to our utility peers. On slide 24, we are reaffirming our 2016 as adjusted EPS guidance of 2.90 to 3.10 per share. In addition, we are maintaining our preliminary as adjusted EPS guidance for 2017 of $3.35 to $3.65 per share. In 2016, we are focused on effectively managing our businesses, integrating SourceGas, and positioning ourselves for strong earnings growth in 2017 and beyond. I will turn it back to Dave now for our strategy update. David Emery Thank you, Rich. Moving on to slide 26, consistent with our past practice for the last couple of years, we group our strategic goals into four major categories, with the overall objective of being an industry leader in everything we do. Moving on to slide 27, our profitable growth objective; our strong capital spending drives our earnings growth. We forecast a total of more than $1.2 billion of investment from the 2016 through 2018 period, positioning us very well to continue our track record of strong earnings growth. It is important to note that we have not included results from our Cost of Service Gas Program in our earnings guidance or our [cap] expenditure forecasts. While we fully expect to implement a Cost of Service Gas Program, the timing and the specific amount of capital expenditures are difficult to forecast currently. Hopefully, we can provide some updates to that forecast after we get through the regulatory process by the end of the year. Moving on to slide 28, as I mentioned earlier, we continue to make excellent progress, constructing our new $65 million, 40-megawatt gas turbine for Colorado Electric. And as I mentioned earlier, we filed [8-K] yesterday to recover both the investment and the expenses for that turbine. Construction is about one-third complete and progressing very well. Slide 29 related to the $109 million, 60-megawatt Peak View Wind project, which will serve our Colorado Electric Utility customers, construction commenced in February, we expect commercial operation by the end of the year. Again as a reminder, that project is being constructed by a third party, and we will assume ownership upon commercial operation. Slide 30, we continue to actively pursue our utility Cost of Service Gas Program, which if approved by our regulators will provide a long-term stable price for gas for our customers, and also a reasonable expectation of lower long-term gas cost for our customers, while providing opportunities for increased earnings for shareholders. As we’ve said before, it is truly a win-win situation. A lot of detail here on this slide about where we are in the various states related to our activity on Cost of Service Gas. As I said earlier, we hope to finalize our Cost of Service Gas Program approvals and then some details related to our forward program prior to the end of the year. On slide 31, we continue to be very proud of our dividend track record. We’ve increased our annual dividend to shareholders for 46 consecutive years and that trend is one we’re re pretty proud of. Slide 32 talks about our credit ratings. Rich already mentioned this, but as he said, all three agencies affirmed our credit ratings following closing of the SourceGas transaction. We are working hard to maintain those ratings. Slide 33 it really illustrates the focus we place every day on operational excellence and on being a great workplace. We made tremendous progress in several categories; I think safety being one that’s very notable. We are very focused on improving our safety performance. As you can see, we’ve made excellent progress over the last several years. Also now this being the first quarter where we are combined with SourceGas, I would like to take the opportunity to thank our employee team, which is now nearly 3000 people strong for the tremendous effort they have exhibited so far in the successful to-date integration of SourceGas and Black Hills. While there is certainly more work to be done, an absolutely incredible amount has already been accomplished in a very short period of time, so thanks to all of the employees for that. It’s an exciting time to work it Black Hills. Moving on to slide 34, this is our scorecard, this is something we’ve done for several years, it’s our way of holding ourselves accountable to you, our shareholders literally setting forth our goals for the year, at the beginning of the year, and marking our progress as the year progresses. That concludes my remarks. We’d be happy to take questions. Question-and-Answer Session Operator [Operator Instructions] our first question comes from the line of Insoo Kim from RBC. Your line is open. Insoo Kim Just starting off at Cost of Service Gas, in Colorado specifically other than the procedural reason for potentially dismissing the original filing, do you have any color as to your conversations with them on some issues I raised regarding the program? David Emery No, not really. I think the biggest single issue for us so far Insoo is that we have not yet received the written order, so we don’t know specifically if there is any additional issue. Until we see that, it’s kind of hard to speculate. We did certainly get the impression that there might be a preference on the part of the commissioners to consider the two phases in a single proceeding. But other than that, it’s pretty hard to provide any color without reading the written order. Insoo Kim Understood. And could you remind us again for this program to be beneficial to customers around what gas level is needed on a longer-term basis? David Emery You mean percent of gas in the program or –? Insoo Kim No, just the natural gas price level needed for the program to be more beneficial to customers to enter in to this type of program? David Emery I think it’s hard to say exactly, because no one knows exactly what gas prices are going to do. But our interpretation as you know you are at a time now where gas prices are probably certainly at a low compared to any recent history, and likely to stay there for at least a period of time, maybe a year or so, maybe a little longer, and we expect them to stay relatively low. If you can lock in gas prices for customers in $3 to $4 dollar range, I think that’s a tremendous long-term result for customers. When you are locking in for the life of the property that’s a tremendous benefit, and now is an opportune time to do that, perhaps one of the best times in the last decade or more to implement a program. So we are optimistic about that. It’s hard to say exactly what the price will be again, not knowing what the forward strip is going to look like at any given point in time and really emphasizing this is about long-term customer cost of gas, not about beating the market in any individual time period. Insoo Kim Understood, and in the Oil and Gas segment given the recent bounce in oil prices from $30 levels, do you expect to be a little more active in trying to make some non-core asset divestitures near-term? David Emery I don’t know if that in and of itself is going to drive our timing on anything. I would say we are already looking pretty aggressively at especially our smaller properties and non-operated interests. We’re working pretty hard at looking at those and we are trying to divest the ones that really don’t make sense for us to hold onto. I don’t think the little bit of bump in oil price affects our timing much. It certainly would be incrementally positive, but the reality of it is, if we divest all those properties it’s not going to be terribly meaningful from a balance sheet perspective anyway. Insoo Kim Got it, and then just last for me for now, in terms of focusing on de-levering the balance sheet beyond 2017, does that imply that you could potentially see continuing a similar level off on the ATM program? David Emery At this point in to our plan it’s just to utilize that through the end of 2017. In 2018, the unit mandatory converts, we think by then we’re going to be back to pretty close to where we like to be, which is 55% debt-to-total cap range, so we’ll see where we are at, at that point. But right now our intent is to utilize the program through the end of 2017. You can see what we’ve included in our guidance relative to that program, and that’s probably as far as we’d go with it at this point barring some other major acquisition or new activity. Operator Our next question comes from the line of Chris Ellinghaus from Williams Capital. Your line is open. Chris Ellinghaus A couple of questions; Rich, have you got the details on what the bridge financing costs were in the first quarter? Rich Kinzley Yes, it’s on the income statement, you can see it there. It’s lined out on that slide as 1.1 million and that ended when we closed on February 12. That was the end of that. Chris Ellinghaus Right, and I’m curious, obviously there were a lot of different moving parts (inaudible) of what I would call unusual items. I am just curious why, as far as the internal labor cost for the merger, why you don’t exclude that as well? Rich Kinzley That’s just our policy, and I think GAAP or internal labor should not be classified as one-time in nature, that’s cost that we will incur next year. They will be redeployed to other activity. Chris Ellinghaus All right, and on page 4, I’m a little bit confused, you mentioned on page 3 in the corporate section the 5.1 million tax benefit that you also referenced in your remarks. But in the footnote on page 4 for corporate, it says tax benefits of 4.4 million. What’s the difference between those two? Rich Kinzley The $5.1 million is made up of two things, Chris, the $4.4 million, the bulk of it was a life time exchange transaction we did back in 2008 when we sold a bunch of power plants and recognized a big gain but deferred that into the Aquila properties. So that was the main item of contention with the IRS that we settled in the first quarter. The additional 00,000 relates to R&D credits that were also in dispute that we’ve settled, and those are scattered across the business units. Operator Our next question comes from the line of Lasan Johong from Auvila Research. Your line is open. Lasan Johong I’m kind of a little confused here, or maybe I’m not doing the math right. But did somebody actually pay you double the construction cost of your Colorado IPP $2150 per KW? Rich Kinzley Well we constructed that plant for $260 million and placed it in service in 2012, and sold 49.9% of it for $215 million this year. Lasan Johong Okay, so close to your double your construction costs. So somebody actually did pay you that. That’s not a mathematical error or anything? Rich Kinzley No, and you did your math right. Lasan Johong Okay, any more details on those (inaudible)? Seriously, I mean if somebody is willing to pay you that kind of money, why not sell the whole portfolio? Rich Kinzley We don’t really have much left Lasan; you know that that one made sense. We’d received several inbound inquiries about that plant, because it’s contracted and it’s in a great location and it’s very clean, and it’s state-of-the-art, a lot of great attributes to that property and in a great market (inaudible) center, everything else. It’s very important for us to continue to own and operate a chunk of that because it’s in the middle of our plant complex that we operate and serve our customers at Colorado Electric, and we thought it was critical for us to maintain control there. But it made sense especially in the context of the SourceGas transaction to sell a minority interest. Lasan Johong Okay, so you think this plant is fundamental to the operations of your (inaudible)? Rich Kinzley Absolutely. Yeah, we’ve got several units on that complex and our wind is interconnected with it. We use it to firm our wind resource in Colorado. It’s very critical to our operation and we prefer to maintain control. It’s best for our customers I think that we do maintain control of that facility. Lasan Johong On the other hand you could build a plant almost double the size for free. But anyway, that’s another story at another time. Getting back on the Oil and Gas situation, look, I hate to put Jerry on the spot here, but he is painting this (inaudible) shale play as something that is kind of akin to a general giga-normous whale, if you want to put it in terms of in those terms. And it kind of makes the Marcellus look like child’s play with three-times the pay zone, good porosity or reasonable porosity and permeability for a shale play. So there are several ways that you could pursue the development. One is to just do a straight development program like you would normally do in oil and gas program. And the alternative is that if you do your Cost of Service Gas Program, which seems like it’s going to move forward, you could make it part of that program, and I’m kind of wondering which way you’re leaning towards; number one, and number two, I think you and I can agree that right now putting together a Cost of Service Cash Program it’s a slam dunk. It is a no-brainer, right, because gas prices being where they are, fundamentals being where they are, it’s an easy decision. But I think we can both agree that initial setup on the program isn’t where you are going to find problems going forward. It’s when you have to buy reserves at a certain point in time down the road that you’re going to get a lot of pushback in this and that and (inaudible) gas prices happen to be higher that you would want to pursue this. So if that’s the case, then the second part of the question is, if you’re pursuing the Cost of Service Gas Program with the (inaudible) shale play in mind, would it not be prudent to use that asset as kind of a drop-down asset to your Cost of Service Gas Program as opposed to just going on developing the Mancos Shale, as if it were a normal oil and gas play where you would (inaudible) in the open market, and this way you can protect your back-door problem with the Cost of Service Gas. So I’m kind of thinking about how you would play the Mancos Shale over a longer period of time. If you could address some of those issues, that would be great. David Emery Sure. I can try to add a little color there. Obviously Lasan one of the things that we are working on is getting through this phase 1 approval process. With that we’ll establish some criteria with the various commissions on what are the properties, the features of a gas property that they would like included in the program and that is step one. I firmly believe that a long term drilling program is a better solution for customers long-term than trying to buy reserves opportunistically. As you know, if you buy reserves in the ground at any given day, the price of those reserves is going to be directly proportional to the forward strip price for natural gas. So right now that’s a good price, and it may make sense for us to buy some properties to kick start if you will the Cost of Service Gas Program. Long-term, we would like to include properties that are similar to the Mancos whether it is the specific Mancos or not but properties like that where you have a good gas resource, very low if almost zero risk of dry holes, very economical, more gas manufacturing if you will, those types of properties are great long-term properties to add for cost of service gas. You can drill them for years; continue to have customers benefit from that program regardless of what the spot price of gas is doing. You are not dependent on the spot price of gas to buy properties to put in the program in any given year. So we like that, we like that feature a lot. Now that being said, the Mancos as a play is not near as mature as the Marcellus. So the production rates, the costs, things like that have not been proven as definitively as the Marcellus. Certainly at the current time the Mancos economics are not as good as the Marcellus so that is part of what we are contemplating is how and when do we propose gradually including the Mancos in a Cost of Service Gas Program if that is what makes sense based on the feedback we get from the commissions going through the process. I do think the Mancos or properties similar to the Mancos make the best long-term sense for customers and that is the direction we prefer to head. We just have to work our way through the regulatory process and get some feedback from the regulators before we make any definitive decision there. Lasan Johong A little curious, because the way it was described to me, the Mancos has 1000 foot pay zone versus the Marcellus, the thickest portion is about 300 feet. Second, your recover reserves per well, I thought was in the 8 to 9 Bcf range versus the Marcellus at a 3 to 5 Bcf range. How is your economics not as good as your Marcellus plays? David Emery Well, there are several things there. The pay thickness isn’t necessarily indicative of how many reserves you’re going to recover, because you can only drain certain vertical area anyway. It may provide an opportunity to vertically stack horizontal wells, because of the pay thickness which isn’t true in the Marcellus. But the Marcellus, some of the initial production rates there and reserve numbers are substantially higher than what we’ve seen in some of our Mancos. Lasan Johong (inaudible) right? David Emery Yeah, and again, it’s a timing thing. There’s only been probably 30, 40 wells drilled in the Mancos in our general area at that depth, and the infrastructure and things aren’t completely built out yet, to where you can really get the economies of scale that they are realizing in the Marcellus right now. I do think a lot of that will come in time, but it is a way off still. Lasan Johong Okay. So it isn’t out of the question that you could use Mancos if developed properly, kind of your solution to longer term replenishment of your Cost of Service Gas reserves? David Emery Yes, it would be a fantastic property for Cost of Service Gas. It’s just a timing issue I think. Lasan Johong Okay, so you’re not thinking of the necessary development of the Mancos as an independent oil and gas play? David Emery No. Operator [Operator Instructions] David Emery Alright, hearing no additional questions, I want to say thanks to everyone for your attendance today. We certainly appreciate your continued interest in Black Hills. We’re excited about what the future holds for us here at Black Hills. We’ve got a lot of great work going on, tremendous growth projects, and a lot of integration activity so stay tuned. We’ve got an exciting year in store. Have a great day. Operator Ladies and gentlemen, thank you again for your participation in today’s conference. This now concludes the program, and you may all (inaudible) your telephone lines at this time. Everyone have a great day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com . Thank you!