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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. 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Upbeat Aerospace And Defense Results Lift ETFs

A major part of the first-quarter earnings season is behind us and a combination of factors including oil price turbulence and global growth uncertainties have weighed on the results . Despite headwinds, aerospace and defense, a relatively smaller sector within the S&P 500, held up well this past quarter. However, it’s not surprising given the low estimates, which had fallen ahead of this reporting cycle. Aerospace and defense stocks have reported better-than-expected results despite sluggish growth numbers. As per the Zacks Earnings Trend report , earnings declined 6.6% while revenues increased 3.8% year over year. The earnings beat ratio of the aerospace and defense companies is 77.8%, while the revenue beat is 88.9% . The U.S. defense sector performed modestly on the back of elevated geopolitical risk, a recovering U.S. economy and strong commercial sales. Escalating geo-political tensions in Eastern Europe, the Middle East and Syria have forced several countries to step up their defense, in turn boosting demand for defense products. Moreover, the aerospace and defense industry has gained from fleet renewals at airlines worldwide. Demand for more fuel-efficient aircraft, a growing international market and increasing application of unmanned aircraft in warfare today have driven up sales in this sector. Below we have highlighted in greater detail the earnings of some of the major aerospace and defense companies which really drive this sector’s outlook. Quarterly Earnings in Focus Pentagon’s prime contractor, Lockheed Martin Corp. (NYSE: LMT ), reported an encouraging first quarter. It reported better-than-expected earnings and revenues with both beating the Zacks Consensus Estimate by 2.8% and 5.5%, respectively. Lockheed Martin raised its 2016 outlook and now expects earnings of about $11.50–$11.80 per share (earlier projection: $11.45–$11.75) on revenues of approximately $49.6 billion to $51.1 billion (earlier projection: $49.5 billion to $51 billion). The stock jumped after the earnings release on solid outlook, impressive revenue growth and potential share buybacks. Aerospace giant, The Boeing Company (NYSE: BA ) delivered first-quarter 2016 adjusted earnings of $1.74 per share, missing the Zacks Consensus Estimate by 3.9%. Earnings also decreased 12% year over year. Revenues came in at $22.63 billion for the quarter, exceeding the Zacks Consensus Estimate of $21.24 billion and increasing 2% from the year-ago level. For 2016, the company still expects earnings to be in the range of $8.15−$8.35 per share on revenues of $93−$95 billion. Investors reacted positively to the company’s results. Northrop Grumman Corp. (NYSE: NOC ) reported upbeat first-quarter 2016 results with revenues and earnings beating the Zacks Consensus Estimate by 0.8% and 12.1%, respectively. The maker of the current B-2 bomber and Global Hawk unmanned planes expects earnings to be in the range of $10.40 to $10.70 per share (prior projection: $9.90–$10.20) on revenues of $23.5 billion to $24 billion in 2016. The stock gained significantly after the company released its results. General Dynamics Corp. ’s (NYSE: GD ) first quarter earnings of $2.34 per share topped both the Zacks Consensus Estimate and the year-ago figure of $2.14 by 9.3%. Revenues of $7.7 billion beat the Zacks Consensus Estimate by 0.4% benefiting from strong demand for defense products during the quarter. Investors reacted positively with the stock gaining after the company released its results. United Technologies Corporation (NYSE: UTX ) reported first-quarter adjusted earnings of $1.47 per share, up 2.1% year over year. The figure also surpassed the Zacks Consensus Estimate of $1.39. Quarterly revenues of $13.4 billion also beat the Zacks Consensus Estimate of $13 billion. However, volatility in foreign currency adversely impacted the revenues of most of the company’s segments during the reported quarter. The company reaffirmed its 2016 guidance. The stock gained post releasing results. ETFs to Play The gains in aerospace and defense companies have put the spotlight on their ETFs. Below, we have these ETFs in detail: iShares U.S. Aerospace & Defense ETF (NYSEARCA: ITA ) The fund, tracking the Dow Jones U.S. Select Aerospace & Defense Index, holds 37 securities in its basket with Boeing, United Technologies, Lockheed Martin, General Dynamics and Northrop Grumman being the top five stocks. All of them together account for more than 38% of the fund assets. With an asset base of nearly $682.7 million, the fund trades in moderate volumes of roughly 83,000 shares a day and charges an annual fee of 45 bps per year. The fund returned 1.25% in the last 10 days (as of May 5, 2016) and has a Zacks ETF Rank #3 (Hold) with a Medium risk outlook . PowerShares Aerospace & Defense Portfolio (NYSEARCA: PPA ) PPA follows the SPADE Defense Index, with 50 companies involved in the development, manufacturing, operations and support of U.S. defense, homeland security and aerospace operations. Lockheed Martin, Boeing, United Technologies, General Dynamic and Northrop Grumman are among the top 10 holdings and together occupy almost one third of total fund assets. The product has managed to garner nearly $296 million in assets so far and trades in an average volume of 76,000 shares per day. It charges 66 bps in annual fees and gained 0.40% in past 10 days. It currently carries a Zacks ETF Rank #3 with a Medium risk outlook. SPDR S&P Aerospace & Defense ETF (NYSEARCA: XAR ) XAR tracks the S&P Aerospace and Defense Select Industry index, holding a basket of 33 stocks. Northrop Grumman, Lockheed Martin, General Dynamics and Boeing score among the top 10 holdings. This product has attracted an AUM of nearly $166.9 million and exchanges nearly 18,000 shares in hand per day. It charges 35 bps in fees per year and gained 1% in the past 10 days. The fund has a Zacks ETF Rank #3 with a Medium risk outlook . Original post

National Fuel Gas Company’s (NFG) CEO Ron Tanski on Q2 2016 Results – Earnings Call Transcript

National Fuel Gas Company (NYSE: NFG ) Q2 2016 Results Earnings Conference Call April 29, 2016 11:00 AM ET Executives Brian Welsch – Director of Investor Relations Ron Tanski – President and Chief Executive Officer Dave Bauer – Treasurer and Principal Financial Officer John McGinnis – Chief Operating Officer Analysts Kevin Smith – Raymond James Holly Stewart – Scotia Howard Becca Followill – U.S. Capital Advisors Operator Good day, ladies and gentlemen and welcome to the National Fuel Gas Company second-quarter 2016 earnings conference call. [Operator Instructions] I would now like to introduce your host for today’s conference, Mr. Brian Welsch, Director of Investor Relations. Please go ahead, sir. Brian Welsch Thank you, Christie and good morning. We appreciate you joining us on today’s conference call for a discussion of last evening’s earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer, Dave Bauer, Treasurer and Principal Financial Officer, and John McGinnis, Chief Operating Officer of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The second-quarter fiscal 2016 earnings release and April investor presentation have been posted on our investor relations website. We may refer to these materials during today’s call. We would also like to remind you that today’s teleconference will contain forward-looking statements. While National Fuel’s expectations, beliefs and projections are made in good faith, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made and you may refer to last evening’s earnings release for a listing of certain specific risk factors. With that I will turn it over to Ron Tanski. Ron Tanski Thanks, Brian and good morning everyone. Thanks for joining us for today’s call. As you saw in our earnings release last evening, we had a pretty steady second quarter although earnings were slightly down from last year. Earnings in our utility segment were lower due to warmer than normal weather and the lower commodity prices decreased earnings in our Exploration and Production segment. Dave Bauer will go into the details of the major earnings drivers later in the call. Overall, activities in the field for each of our operating segments moved right along as planned. We are just gearing up for the construction season for our regular pipeline renewal projects in our utility and our Pipeline and Storage segments. At the same time, we’ve slowed the drilling activities at Seneca Resources by moving to a single rig drilling program. Our reduced drilling level combined with getting a partner to fund a large portion of this year’s drilling program has cut our spending to allow us to leave within cash flow for the year. Our current plans allow us to stay to single drilling rig for at least a year before we need to ramp up drilling and completion activities again in order to have enough production to fill the pipeline capacity that will come online in November of 2017, the targeted completion date of our Northern Access pipeline. With respect to our Northern Access project, we received some good news from the Federal Energy Regulatory Commission. At April 14th, FERC issued its notices schedule for environmental review for the project and it confirmed their intention to develop an environmental assessment or EA for the project and announced the July 27, 2016 target date for the EA. Now that fits within our timeline for November 2017 in-service date. The other recent news on the regulatory front is the denial by the New York DEC of the Federal Water Quality Certification for the Constitution Pipeline project in Southeastern New York. We submitted our own permit filings to the New York DEC, the Pennsylvania Department of Environmental Protection and the U.S. Army Corps of Engineers for our project just last month. We delayed our filing by three months after a number of pre-filing meetings with the staff of the DEC in order to make sure that our application was complete and address their stated concerns. Based on those pre-filing meetings and gleaning what information we can from the Constitution denial letter, we feel our application is in pretty good shape. A big plus for our project is that more than 75% of the pipeline route will be co-located along existing utility corridors. We also believe that we worked well with the DEC in the past. We already owned and operated thousands of miles of pipeline assets in the state and during our ongoing maintenance and renewal of those lines we’ve dealt with them on a regular basis, addressing many project specific issues. Suffice it to say that we are confident that our project will continue to move along. On the federal rate regulatory front, our team has been busy filing the required cost and revenue study for our Empire Pipeline and answering interrogatories from FERC staff regarding the filing. The schedule is set out by the administrative law judge is a target completion date for the proceeding is set for February of 2017. So, we will keep you posted in future calls if anything major happens in that case. Switching to our utility and state rate regulation, our utility rate team filed a request for a rate increase in New York yesterday. This is the first rate increase request the utility has made since early 2007. The filing supports a $41.7 million increase in base rates, an increase of approximately $5.75 per month for an average residential customer. As is typical in the New York rate proceeding, any new rates would not become effective for 11 months. So, we wouldn’t expect any earnings impact until the second half of next fiscal year. We have a pretty clear line of sight through the end of this fiscal year with respect to our earnings projections and you can see that we’ve tightened up our earnings guidance range. With respect to our oil and gas production, we are well hedged for the remainder of this fiscal year and next fiscal year. And as you can see in the back pages of our earnings release, we are continuing our normal practice of layering in hedges for our oil and gas production as commodity prices in the futures market for our fiscal 2018 and beyond have begun to firm up. We see the market getting more bullish on commodity prices in the out years as production volumes have started to level off and the rig count stays low. For the foreseeable future, we will continue to watch our spending, protect our balance sheet and work to get our Northern Access pipeline build that will deliver Seneca’s production to an attractive pricing point. Now, I will turn the call over to John McGinnis, who will be stepping into the role of President at Seneca, when Matt Cabell’s retirement becomes effective next week. John McGinnis Thanks, Ron, and good morning everyone. For the fiscal second quarter, Seneca produced 39.2 Bcfe, which suggest over a Bcf more than we produced in our first quarter. In Pennsylvania, we curtailed approximately 9.1 Bcf of potential spot sales due to low prices and as a result, no spot gas was sold during the first half of our fiscal year. In April, however, prices have actually improved to the point but we have intermittently produced into the spot market at both our Tennessee and Transco receipt points. Though not a large volume totaling just over a Bcf, this was the first time we have sold meaningful spot volumes since December of 2014. In Pennsylvania after beginning the year with three rigs, we have now dropped to a single rig as of March. We plan on keeping this rig active for the remainder of the year to ensure we have sufficient inventory of DUCs to help fill Northern Access now scheduled to be online late next year. We have also reduced the activity level related to our completions crew to daylight-only operations. At this reduced pace, we typically complete five to six stages per day, which allows us to continue to recycle all of our produced water and avoid costly water disposal. Even with our frac crew operating at half pace, we continued to drop our well costs. For the first half of 2016, our development program has averaged under $5 million per well for a 7,400 foot lateral, which equates to costs of around $675 per foot. The key drivers for this continued drop in costs include the impact of the new frac contract executed in September of 2015 and a significant reduction in water costs. We now average less than a dollar per barrel in water costs, compared to about $3 per pad early in our development program. Moving now to the Utica/Point Pleasant, we have drilled and completed our first Clermont area at Utica horizontal at an estimated cost of just over $7 million. This well was drilled with a relatively short lateral length of 4,500 feet to better understand productivity on a per foot basis. Once we have completed all of 11 wells on this pad, 10 of which are in the Marcellus, we will bring this pad into production later this summer. The rig has recently moved to a new pad also in the Clermont area where we are currently drilling our second Utica well. This well is scheduled to be tested early in 2017. On the marketing front, when the opportunity arises, we continue to layer in fixed price sales and firm sales tied to financial hedges. This has allowed us to slowly grow production and realize acceptable pricing during an exceedingly difficult period for commodity prices. For the remainder of our fiscal 2016, the vast majority of our natural gas production forecast around 64 Bcf is locked in both physically and financially at an average realized price of $3.20. This $3.20 is net of firm transportation. We also have an additional 4 Bcf of basis protection and with the recent improvement in futures pricing, we are actively pursuing additional opportunities to add to our physical sales portfolio and hedge book. In California, production was nearly flat quarter-over-quarter, even though we have significantly cut our spending in California this year. We’re targeting to spend just under $40 million in 2016, almost a 30% reduction in compared to last year and half of what we spent just two years ago. All of our development activity is focused in Midway Sunset and will remain so until prices rebound. As a result of our recent farm-ins, however, we believe we can keep production flat to slightly growing over the next couple of years, even with these capital cuts. Thus far in 2016, we have cut E&P capital expenditures by almost 70% compared to 2015 levels to a forecasted range of $150 million to $200 million. Even with these cuts, we expect to grow our production slightly this year and maintain our DUC count ahead of Northern Access in-service date. The key drivers in achieving this result include our recent joint development agreement with IOG, dropping to a single rig and moving to daylight-only frac operations in Appalachia, combined with again, a significant reduction in our California capital expenditures. I’d like to now turn the call over to Dave Bauer. Dave Bauer Thanks, John. Good morning, everyone. Excluding the ceiling test charge, earnings for the quarter were $0.97 per share, down $0.05 from last year. The unseasonably warm weather in our service territory relative to last year’s record cold, lowered earnings by a combined $0.11 in our utility and Pipeline and Storage businesses. Meanwhile, our ongoing focus on cost control across the system helped to offset the continued weakness in oil and gas prices, which lowered earnings by about $0.25 per share. All told, considering the twin headwinds of weather and commodity pricing, both of which are largely beyond our control, the second quarter was a good one for National Fuel. Seneca’s production was up nearly 10% over last year’s quarter and 3% on a sequential basis. This increase is largely attributable to Seneca’s firm transportation capacity and associated firm sales related to the Northern Access 2015 project, which was placed in service late in calendar 2015. As a reminder, this was a joint project between our NFG Supply Corporation subsidiary and Tennessee Gas Pipeline designed to move a 140,000 dekatherms per day from our WDA acreage to the Canadian border at Niagara. For the quarter, this project contributed over $3 million in revenues to our Pipeline and Storage segment. In addition to benefiting Seneca and Supply Corp, the increase in Seneca’s production combined with our partner IOG’s share of the volumes from the joint development wells also helped our gathering business where revenues were up by $4.2 million or nearly 25%. Controlling operating costs was a focus across the system and we saw excellent results during the quarter. At Seneca, per unit LOE was $0.96 per Mcfe, down $0.07 from the first quarter. Most of this decrease was attributable to our California operations. In light of lower oil prices, our team has kept a tight lid on expenses, limiting our spending to only highly economic work-over activity and to areas that are critical to the safety and integrity of our assets. Also, lower natural gas prices caused steam fuel cost to be lower than we expected. In Appalachia, lower water disposal costs were also a factor. As John said, Seneca is now reusing almost 100% of our produced water. Road maintenance expense was also lower due to the relatively mild winter. Given all of these factors, we now expect our full-year per unit LOE rate will be in the range of $0.95 to a $1.05 per Mcfe, down $0.05 from our previous guidance. Seneca’s per unit G&A expense was $0.49 per Mcfe. During the quarter, Seneca implemented a reduction in force that trimmed our staffing complement by about 10%. As part of that effort, we paid out severance costs of about $1.5 million, which caused Seneca’s per unit G&A to be about $0.04 higher than it otherwise would’ve been. We’ll start to see lower personnel costs in the second half of the year. Per unit G&A for the rest of the fiscal year should be in the range of $0.35 to $0.40 per Mcfe. At utility, O&M costs were down over $5 million from last year. About a third of this decrease was caused by lower bad debt expense. A combination of historically warm weather and exceptionally low natural gas prices caused our customers winter heating bills to be the lowest they’ve seen in decades and has had a meaningful impact on our bad debt expense. The remainder of the decrease was caused by a variety of factors, including lower maintenance expense that was the result of the mild winter and lower pension and personnel-related expenses. In the Pipeline and Storage segment, revenues were up just about a $1 million from last year. While this may seem light, given the projects that were placed in service in the first quarter of the fiscal year, the swinging weather year-over-year had a significant impact on revenues from short-term firm services which decreased by approximately $5 million from last year. We expect larger favorable variances in revenue for the last two quarters of the year and still expect revenues in the segment to total between $300 million and $310 million for the full year. Looking to the remainder of the year, we are tightening our earnings and production guidance ranges. Our new earnings guidance while unchanged at the midpoint is a little tighter at $2.80 to $2.95, excluding ceiling test charges. Seneca’s updated production forecast is now a 158 to a 175 Bcfe. We up the low end of our previous guidance range of 150 to a 180 Bcfe to reflect new firm sales that were done this quarter, as well as some minor changes in our operations schedule. We lower the high end to reflect curtailments from the second quarter. As in prior quarters, the difference between the high and low end of our production range is driven entirely by curtailments. The low-end assumes we curtail a 100% percent of our spot production while the high-end assumes we have no curtailments. While we didn’t have any spot sales during the first six months of the year, as John mentioned we’ve sold about a Bcf spot sales in April which is encouraging. We have also made a modest change to our NYMEX natural gas price assumption which is now $2.15, down $0.10 from our previous guidance. Our oil price assumption is unchanged at $40 a barrel. We are well hedged for fiscal ‘16 for the remainder of the fiscal year and assuming the midpoint of our production guidance, we are about 80% hedged for natural gas and 55% for crude oil. Therefore, any changes in commodity prices should have a relatively modest impact on our cash flows. We continue to actively pursue incremental hedges in firm sales to lock in the economics of our program, as we grow into the volumes that are required to fill the Northern Access and Atlantic Sunrise projects. Just recently, we added a modest layer of Dawn and NYMEX-based hedges for 2018 to 2021 time period at about $3 per MMbtu. Consolidated capital spending for fiscal ‘16 is expected to be in the range of $445 million to $545 million, down $20 million from our previous range. Substantially, all of the change is related to the timing of spending between 2016 and 2017. Details of capital spending plans by segment are included in the new IR deck on our website. From a liquidity standpoint, we continued to be in great shape. Assuming the midpoint of our earnings and capital spending guidance, we expect we are very close within cash flows for the fiscal year. With that I will close and ask the operator to open the line for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] Our first question comes from the line of Kevin Smith of Raymond James. Your line is open. Kevin Smith Thank you and good morning, gentlemen. John McGinnis Hi, Kevin. Kevin Smith John, congrats first on joining the earnings call but with that, I will kick off the question. Can you discuss current shut-in volumes in the Marcellus and maybe how much you’ve been able to sell to spot since differentials have been tightening? John McGinnis Say that again. I’m sorry, you are breaking up. Kevin Smith I apologize about that. Can you discuss current shut-in volumes in the Marcellus and then maybe how much you’ve been able to sell into spot and what that’s looked like over the last month? John McGinnis Yes. We’ve sold essentially nothing in spot for the second quarter, a little over a Bcf in April because prices had improved upon we could, both on Tennessee and Transco sell into the spot market. But recently though pricing has dropped off again so we are shut-in. But I think we are about $40 million to $50 million of available spot in our Tioga area and a little over 100, 120 in Lycoming if I remember correctly. Kevin Smith Got you. That’s helpful. And would you mind providing some more details about the new firm sales agreements? Basically what’s the length of those contracts? Dave Bauer Yes. Sure, Kevin. This is Dave. We did — well for fiscal ’16, we did about 5 Bcf of additional firm sales and then looking out into ’17, ’18, ’19, we did a bunch of fixed sales ranging, call it from 10 to 30 Bcf per year, kind of in the high but just under $2 range. Kevin Smith Okay. Great. That’s extremely helpful. That’s all I had. Thanks. Dave Bauer Sure. Operator Thank you. [Operator Instructions] And we do have a question from the line of Holly Stewart of Scotia Howard. Your line is open. Holly Stewart Good morning, gentlemen. John McGinnis Hi, Holly. Holly Stewart Maybe just one on sort of what you see on the capacity market in Northeast PA. I mean the rig count, I think in Northeast PA has dropped to maybe three now. Just curious if you’ve seen a pickup in capacity being offered out there and sort of what you are looking at in terms of volume, maybe a pickup in order to bring some of that volume on — some of your shut-in volume online? John McGinnis I think it’s actually down to two rigs now. I was just looking at that the other day. It continues to fall. We haven’t seen any help on the capacity side as of yet. Whether producers are bringing on wells as they had shut in, we just — we haven’t seen additional, at least significant additional capacity available in that part of the state. Holly Stewart Okay. Okay. Great. And then maybe you could just help us think about the progression of production for the next few quarters, give us your wells turned to sales during this past quarter and then sort of the remaining target for the year? John McGinnis Yes. I can give you our target for the year. I can’t tell you what the second quarter was. We are targeting for fiscal ‘16 about 50 wells to drilled, 45 to be completed. We will end the year with about 60 to 65 DUCs. And in terms of the well count, back half of the fiscal year, we are looking at bringing on an additional about 25 wells. Holly Stewart Okay. Great. Thanks, John. John McGinnis Yes. Operator Thank you. And our next question is from Becca Followill of U.S. Capital Advisors. Your line is open. Becca Followill Hi guys. John McGinnis Hi Becca. Becca Followill You talked a little bit. I know you’ve had the one-rig program. What does it take to start to ramp that back up again? John McGinnis Well, part of why we want to keep a single rig going is that it keeps in the half, sort of the daylight-only or what I call a half frac crew is that it keep our DUC count relatively flat. And so really to ramp-up, it doesn’t really — we are not going to necessarily need to bring in an extra rig. What we will end up doing is we will go to 24-hour frac crew and potentially two frac crews, obviously — depending on the ops and the in-service date related to Northern Access. So really it’s more to bring in an additional frac crews as opposed to a rig count. Becca Followill Thank you. And then on the water permit, what is the timing you’re expecting to get that permit from the DEC? John McGinnis Well, assuming that it takes the full year, Becca, it would be the beginning of March of 2017. Are you getting that? Becca Followill Do you think it will take the full year? John McGinnis I think we’ve — that’s kind of what we have planned at the outside. We had the luxury of being on 98% of the route sites, so that we had what we think was a very, very complete application. Whether that state will move it along any faster, we can’t guarantee. We just know that there is a year timeframe from filing. So that’s what we are planning on. Becca Followill Thank you. And then lastly on the Empire open season. I think there was something in the slide deck about precedent agreements were tendered in February. So, can you talk a little bit about that expansion? John McGinnis Well, we are working through that. We did have a good open season for the Empire North project. It was — to a certain degree it was oversubscribed because certain parties tried to put together different combinations of transportation routes and so that’s really what we’re working through, Becca, in order to kind of rationalize the best flows and the best combination and get that worked in to precedent agreements. We don’t have any of them signed just yet and we just continue to work away at that. Becca Followill Okay. Thank you. Operator Thank you. And our next question is from Chris Sighinolfi of Jefferies. Your line is open. Unidentified Analyst Hey guys. Good morning. This is actually Chris Dillon [ph] on for Sighinolfi. How are you? John McGinnis Hi, Chris. Dave Bauer Good, Chris. Unidentified Analyst I was just wondering if you could provide an update on the JV and whether or not you feel like the partner is likely to exercise the option there as we approach that date and what I guess, kind of conversations you are having and what might be under consideration from their side? John McGinnis The relationship is great. We drilled 30 of the 42 wells. With those pads just — they are early. They are just now coming online. Our costs have been about 10% or more down which they are pleased with. We have conversations around entering into the second tranche, but really that’s a decision that they are going to make in July and that’s really all I can speak to right now on that. Unidentified Analyst Okay. That’s fair. That was it for me. Thanks guys. Operator Thank you. And that does conclude our Q&A session for today. I would like to turn the call back to Mr. Brian Welsch for any further remarks. Brian Welsch Thank you, Christie. 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