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National Fuel Gas’ (NFG) CEO Ron Tanski on Q3 2015 Results – Earnings Call Transcript

National Fuel Gas Company (NYSE: NFG ) Q3 2015 Earnings Conference Call August 07, 2015 11:00 AM ET Executives Brian Welsch – IR Ron Tanski – CEO Dave Bauer – Treasurer and Principal Financial Officer Matt Cabell – President of Seneca Resources Corporation Analysts Becca Followill – U.S. Capital Advisors Holly Stewart – Howard Weil Chris Tillett – Jefferies Operator Good day, ladies and gentlemen, and welcome to the Q3 2015 National Fuel Gas Company Earnings Conference call. My name is Halley, and I am your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I’d now like to turn the call over to Mr. Brian Welsch, Director of Investor Relations. Please proceed, sir. Brian Welsch Thank you, Halley, 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 Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open up the discussion to questions. The third quarter earnings release and August inventor 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’ll turn it over to Ron Tanski. Ron Tanski Thanks Brian and good morning everyone. Operating earnings are $0.55 per share for the third quarter or $0.18 per share lower than the last year’s third quarter. If you look at the drivers of that decrease that we breakout on page 11 of the earnings release it’s easy to see that three items in our exploration and production segment explain most all of the year-to-year decrease. Those items were lower commodity prices, decreased production and offsetting the first two items the reduction in our DD&A rate. The decrease in production is largely a result of our shutting in wells in Appalachian when the spot prices are too low. We continue to look for opportunities to sale our spot production at acceptable prices but there is simply too much gas and not enough pipeline infrastructures to move those supplies to attractive price points. As we pointed out in the release we curtailed approximately 12.5 Bcf of production during the quarter. Lower commodity prices have obviously been the story for most energy companies this earning season and we’ve seen some firms make major reductions in their capital expenditure budgets. We’re watching our spending too, but I’ll remind everyone that our CapEx plans have always been relatively conservative. Our current rig scheduling and drilling programs are designed to bring on enough production to fill the pipelines that we’re building to move their production to better pricing points. We continue to move forward with our plans to build the pipelines to help move production out of the basin both for owned Seneca Resources and for third party producers. Construction is underway on three of our interstate pipeline projects. Our West Side expansion project along our line and corridor, our Tuscarora Lateral project in the more central portion of our system and our Northern Access 2015 project, all of these projects are moving along on schedule and we expect that they will all be in service in the last quarter — calendar quarter of this year. The Northern Access 2015 project will allow Seneca to move140,000 dekatherms per day of gas to Canada at the Niagara interaction with TransCanada and the West Side expansion will allow Seneca to flow an additional 30,000 dekatherms per day, a portion moving to Canada and the remainder to Texas Eastern. We have shown Seneca’s transportation capacity graphically on Page 24 of our Investor Relations slide deck on our website. When combining this 170,000 dekatherms of near term capacity with the 490,000 dekatherms per day of capacity, that Seneca has in our Northern Access 2016 project you can see that we’ve got a substantial growth trajectory moving forward from our current productive capacity of 150,000 dekatherms per day in our western development area. Both Matt and Dave will give some more color on our marketing activities and hedging positions. But I am pleased to say there ongoing approach of regularly layering in hedges has put us in good shape with respect to revenue certainty for a good portion of our firms sales for the rest of this year and next fiscal year. Lower commodity prices have obviously cut into our earnings but our diversified model continues to produce healthy cash flow. Our balance sheet is in good shape but I don’t see any need to alter our strategy to build more pipelines and drilled the wells necessary to fill those pipelines. These investments help us accomplished two goals they generate significant cash flows for at least the next 15 years and they provide Seneca’s with the ability to move gas to our market with significantly better pricing. This integrated approach to developing our assets combined with the flexibility offered by our fee mineral acreage position is allowing us to deal with the current pricing challenges and puts us in a great position for continued growth. Our financing requirements for 2015 and 2016 are meaningful but our outspend is driven almost entirely by our investments and our long term midstream infrastructure. Dave will talk about the debt financing we completed in June to cover our 2015 capital program. And looking ahead in next fiscal year as we’ve said in the past the MLP structure is an option that we’re evaluating for our midstream business and given the right market condition we think it’s a very good option. The MLP market and frankly the entire energy space is under pressure right now but markets go up and down and just because there is a dislocation today doesn’t mean it will continue forever. And MLP is not only option, there are number of ways to finance our business. We’re certainly aware of our capital needs in fiscal 2016 and we’ll pick the financing option that we think is best for our shareholders. One thing is clear, there is lot of capital looking to be put to work in the midstream space. We have a great set of assets a great management team and a great plan to grow the business. In the end those are key to attracting the best sources of capital. Now I’ll turn the call over to Matt Cabell to give Seneca update. Matt Cabell Thanks Ron and good morning everyone. For the fiscal third quarter Seneca produced 36.2 Bcfe which is 11% or 4 Bcfe less than last year’s third quarter. However during this year’s third quarter we sold only our firm volumes in the Marcellus and curtailed 12.5 Bcf or approximately 140 million cubic feet per day of potential spot sales due to low prices. Absent those curtailments production would have been up 20%. In California our 2015 drilling programs have had good results and provide attractive returns even at today’s low prices. At $50 oil we earn returns of 30% to 40% on wells we drilled in the North Midway, South Midway and East Coalinga areas which represents the majority of our current and fiscal 2016 capital budget. We are also feeling good about our opportunities to grow California production over the next several years due to opportunities we see at East Coalinga and add two additional farm-in deals that are near in completion. I hope to have these two deals inked by the next call and we’ll provide some details then. Moving on to the Marcellus development in the Clermont Rich Valley areas is going well with 52 Clermont area wells drilled in the first nine months of fiscal ’15 and 24 completed. Our most recent completion in the North half of our E9E pad came on at rates ranging from 8.5 million to 10 million cubic feet per day. IP rates and EURs have been remarkably consistent in the CRB area. We also continue to drive down drilling and completion cost. Our average fiscal 2015 development well cost was $5.8 million for a 36 stages well with 7,000 foot lateral length. On the marketing front we continue to take a portfolio approach to our marketing arrangements. Optimizing the value of our firm transportation while minimizing risks through a series of firm’s sales. For example this November the Northern access 2015 project will go into service we have 140,000 dekatherms of firm transport capacity locked up under firm sales contracts with Dawn Index pricing. Dawn continues to trade a premium, so we were able to convert a portion of the Dawn sales contracts to NYMEX plus $0.35 per MMBtu for November 1 through March 31. In addition, we recently requested proposals to purchase a portion of the gas we will transport in the Northern Access 2016 project. We were pleased with the diversity and number of parties that participated and are currently negotiating a mix of Dawn Indexed and fixed price deals tied to a portion of our capacity on the project. Our active marketing and hedging program has gone long way to insulate Seneca from low natural gas prices. For the third quarter our average after hedging sales price was $3.32 per Mcf, which is over a $1 higher than the pre-hedged price. Looking forward to fiscal 2016 we now have a 114 Bcf of our gas production locked in both physically and financially at an average price of $3.50 per Mcf so we are well positioned should low prices persist in to next year. Moving now to the Utica, I am sure that many of you saw the high rate test that we announced by our peers in Westmoreland and Green Counties. We have two Utica test planned that should connect the trend between these recent wells and Tioga County where our recent Utica well tested 22.7 million cubic feet per day. As I mentioned on our last call the planned wells will be drilled in conjunction with our ongoing Marcellus development in the Clermont area. The rig is just moved to the E9-M pad where we plan to drill 10 Marcellus wells and one Utica. This will be a 5,500 foot lateral with an expected total cost of about $12 million. We expect to frac this pad in the third quarter of fiscal ‘16 and should have a test rate shortly thereafter. Given our larger contiguous fee acreage position a successful Clermont area Utica test could have a major impact on Seneca’s overall resource potential. In summary, our development program continues to show consistent predictable results. We are driving down costs and locking in margins through firm sales and hedging, although we’re dropping a rig early in ‘16 and reducing our capital spending from 2015 to 2016. We are on track to fully utilize the 700,000 dekatherms of firm transportation that we’ll have in 2017 and in addition to thousands of de-risked Marcellus well locations. We are optimistic about the potential for Utica development across a broad swap of our acreage. With that I’ll turn it over to Dave. Dave Bauer Thank you, Matt. Good morning everyone. Ron hit on the major drivers for the quarter’s earnings and other than the impairment charge there really wasn’t anything unusual on the quarter. Last night release explains the major variances in earnings, so I won’t repeat them again here. Instead I will focus on our expectations for the remainder of the fiscal year and our initial guidance for next year. With respect to 2015 our updated earnings guidance is $2.90 to $3 per share excluding ceiling test impairments. That’s up from our previous range of $2.75 to $2.90 mostly due to lower expected DD&A expense. As a result of the third quarter ceiling test charge we expect Seneca’s per unit DD&A rate for the fourth quarter will be in the $1.35 per Mcfe area. That will lower the full year DD&A rate to about $1.55 per Mcfe at the low end of our previous guidance of $1.55 to $1.65. Production for the year is now expected to be 155 to 160 Bcfe. The midpoint is the level should achieve assuming we don’t sale any spot volumes in August and September. We haven’t produced above our level of firms sales commitments for the better part of the calendar year and based on the prices we’ve seen thus far we don’t think it’s likely we’ll have meaningful spot sales in the remainder of the fourth quarter. However should prices improved, we have the ability to produce about 4 Bcf per month into the spot markets. In terms of pricing we’re assuming Henry Hub price for natural gas of $2.75 per Mcf. However because all of the 2 Bcf of our firm sales for the quarter are hedged changes in natural gas price saw minimal impact on our earnings. For crude oil we’re assuming WTI price of $50 a barrel. That’s little higher than the current IMX [ph] prices, we are better than 60% hedge for the fourth quarter. Looking to next year our preliminary earnings guidance for fiscal ‘16 is a range of $3 to $3.30 per share excluding any ceiling test impairment charges. In terms of pricing we’re assuming a Henry Hub gas price of $3.25 per Mcf and a WTI crude oil price of $55 a barrel. In addition we’re assuming we’ll receive $1.75 per Mcf for Marcellus spot buy-ins. There has been considerable volatility in commodity prices particularly with respect to crude oil and we expect to refine our pricing assumptions as we move into the fiscal year. Seneca’s production forecast of 158 to 232 Bcfe has a wider than normal range which reflects the uncertainty around Appalachian gas pricing and our ability to sell spot volumes at an acceptable price. We’re optimistic that Seneca will have spot sales, but want to manage expectations given our recent experience. Therefore, we’re presenting a full range of potential outcomes. If we saw a 100% of our expected spot volumes will be at the high end of the range, if we don’t sale any spot volumes will be at the low end. From an expense standpoint the ranges you see on page 25 of last night’s release are all based on the 195 Bcfe mid-point of our production forecast. The improvements in per unit LOE, G&A and production tax expenses compared to our third quarter rates are attributable to the expected increase in Seneca’s production volumes. As you’d expect our DD&A rate will decrease sharply as a result of the ceiling test impairments. So we excluded our future ceiling test charges themselves from our earnings guidance. We have tried to estimate with the DD&A rate will look post impairments. However given number of variable that go into that calculation it’s possible the range will change meaningfully in the coming quarters. As you can see from pages 56 to 57 of our new IR deck we’re well hedged for fiscal ’16 and as Matt said earlier, we’ve locked in 114 Bcf of natural gas production at a price of about $3.50 per Mcf. And that equates to about 80% of our firm sales volumes and at the midpoint of our production forecast about 65% of our expected natural gas production. On the oil side we have about 1.3 million barrels hedged at $93 barrel which represents about 45% of our expected oil production. Together the excitement earnings and cash flow should track the increase in Seneca’s volumes. For fiscal ’16 assuming the midpoint of Seneca’s production forecast we expect the gathering excitements revenues will be about $95 million up from the 75 million to 80 million we forecast for fiscal ’15. As we add compression to Clermont system operating and depreciation expenses will increase meaningfully relative to their current levels. But a large portion of the revenue increase should fall to the bottom line. Turning to the regulated businesses fiscal ’16 should be a good year for the pipeline and storage segment. This fall the Northern Access 15, West Side expansion and Tuscarora Lateral projects go into service adding $27 million of incremental revenues in 2016. However that increase will be likely offset in part by a variety of smaller items including some typical re-contract again both pipeline system and a decrease in short term transportation revenue is somewhat weather related and recall the last winter was significantly colder than normal. Our forecast for 2016 assumes normal weather. Considering those items we expect pipeline and storage revenue for fiscal ’16 will be in the range of $300 million to $310 million. We expect ONM expense in this segment will increase to about $85 million to $90 million part of that increase relates to higher operating cost associated with our recent expansion projects and part relates to an expected $4 million increase in the retirement benefit cost which is driven by some anticipated changes in our plans actuarial assumptions. Lastly with respect to the utility, we’re expecting a decline in that segment earnings in fiscal ’16 for two reasons. First as I just mentioned our forecast assumes normal weather. In fiscal ’15 colder than normal weather contributed about $0.05 per share at earnings. Additionally, as you recall in the second quarter of fiscal ’15 an audit in the New York division of the utility resulted in an adjustment to benefited earnings by about $0.04 of share. And we don’t expect that adjustment will recur in 2016. Turning to capital spending page 7 of our new IR deck contains our updated capital spending estimates for fiscal ’15. We narrowed our consolidated guidance to a range of 990 million to 1.045 billion at the midpoint of $55 million decrease from our previous guidance. About half of the decrease is related to the timing and spending between fiscal years in the E&P gathering and pipeline segments. The other half relates to the utility Dunkirk project at the timing of which is become less clear. The owner of the power plant that would be served by the project is facing some legal and regulatory challenges with respect to its repurchasing of the plant. We stand ready to build the project once those challenges are resolved but given the uncertainty we are removing the project form our capital budget. For fiscal ’16 our consolidated range is now 1.1 billion to 1.3 billion, up modestly from our previous guidance. There aren’t any major changes in our spending plans the variation are mostly attributable to timing. Given the changes in our earnings and capital spending guidance we now expect and outspend in fiscal ’15 that’s just under $400 million. In June we issued $450 million of long term debt to fund that outspend. Looking to next year we expect our capital expenditures and dividend, we’ll exceed cash from operations in the range of 500 million to 600 million. We have short term credit facilities to initially finance that outspend if it’s necessary and as you know we’re evaluating longer term financing alternatives. As a place older our earnings guidance for fiscal ’16 assume we use terms we used short term debt and we’ll obviously updates that guidance we refine our ultimate financing finance. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instruction] Our first question comes from Becca Followill, U.S. Capital Advisors. Please go ahead. You are now live in the call. Becca Followill Couple of questions for you, one I know that you sounded you’ve taken off some of the list in the short term in the Dawn hedges in favor of a higher NYMEX price. What we’re seeing so far is what we have tried to estimate with the DD&A rate will look post impairments. However given number of variable that go into that calculation it’s possible the range will change meaningfully in the coming quarters. As you can see from pages 56 to 57 of our new IR deck we’re well hedged for fiscal ’16 and as Matt said earlier, we’ve locked in 114 Bcf of natural gas production at a price of about $3.50 per Mcf. And that equates to about 80% of our firm sales volumes and at the midpoint of our production forecast about 65% of our expected natural gas production. On the oil side we have about 1.3 million barrels hedged at $93 barrel which represents about 45% of our expected oil production. Together the excitement earnings and cash flow should track the increase in Seneca’s volumes. For fiscal ’16 assuming the midpoint of Seneca’s production forecast we expect the gathering excitements revenues will be about $95 million up from the 75 million to 80 million we forecast for fiscal ’15. As we add compression to Clermont system operating and depreciation expenses will increase meaningfully relative to their current levels. But a large portion of the revenue increase should fall to the bottom line. Turning to the regulated businesses fiscal ’16 should be a good year for the pipeline and storage segment. This fall the Northern Access 15, West Side expansion and Tuscarora Lateral projects go into service adding $27 million of incremental revenues in 2016. However that increase will be likely offset in part by a variety of smaller items including some typical re-contract again both pipeline system and a decrease in short term transportation revenue is somewhat weather related and recall the last winter was significantly colder than normal. Our forecast for 2016 assumes normal weather. Considering those items we expect pipeline and storage revenue for fiscal ’16 will be in the range of $300 million to $310 million. We expect ONM expense in this segment will increase to about $85 million to $90 million part of that increase relates to higher operating cost associated with our recent expansion projects and part relates to an expected $4 million increase in the retirement benefit cost which is driven by some anticipated changes in our plans actuarial assumptions. Lastly with respect to the utility, we’re expecting a decline in that segment earnings in fiscal ’16 for two reasons. First as I just mentioned our forecast assumes normal weather. In fiscal ’15 colder than normal weather contributed about $0.05 per share at earnings. Additionally, as you recall in the second quarter of fiscal ’15 an audit in the New York division of the utility resulted in an adjustment to benefited earnings by about $0.04 of share. And we don’t expect that adjustment will recur in 2016. Turning to capital spending page 7 of our new IR deck contains our updated capital spending estimates for fiscal ’15. We narrowed our consolidated guidance to a range of 990 million to 1.045 billion at the midpoint of $55 million decrease from our previous guidance. About half of the decrease is related to the timing and spending between fiscal years in the E&P gathering and pipeline segments. The other half relates to the utility Dunkirk project at the timing of which is become less clear. The owner of the power plant that would be served by the project is facing some legal and regulatory challenges with respect to its repurchasing of the plant. We stand ready to build the project once those challenges are resolved but given the uncertainty we are removing the project form our capital budget. For fiscal ’16 our consolidated range is now 1.1 billion to 1.3 billion, up modestly from our previous guidance. There aren’t any major changes in our spending plans the variation are mostly attributable to timing. Given the changes in our earnings and capital spending guidance we now expect and outspend in fiscal ’15 that’s just under $400 million. In June we issued $450 million of long term debt to fund that outspend. Looking to next year we expect our capital expenditures and dividend, we’ll exceed cash from operations in the range of 500 million to 600 million. We have short term credit facilities to initially finance that outspend if it’s necessary and as you know we’re evaluating longer term financing alternatives. As a place older our earnings guidance for fiscal ’16 assume we use terms we used short term debt and we’ll obviously updates that guidance we refine our ultimate financing finance. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instruction] Our first question comes from Becca Followill, U.S. Capital Advisors. Please go ahead. You are now live in the call. Becca Followill Couple of questions for you, one I know that you sounded you’ve taken off some of the list in the short term in the Dawn hedges in favor of a higher NYMEX price. What we’re seeing so far is what direct reversal completion that just trying to get basis for in Chicago, can you talk little bit about your capacity going to Dawn on and how much you have hedged. In the out years thoughts which is short debt maybe 17, 18, 19? Ron Tanski You have referenced from the slide deck. Back on page 27 is our IR deck is our hedge positions going out. We don’t have a larger amount of longer term hedges in place for 2016 we have 19 Bcf at Dawn, 2017, 22 Bcf and a more modest amount financially hedged that fit on. Becca Followill Is there enough liquidity to hedge out some of this in future years? Dave Bauer We are looking at that and we haven’t looked much beyond 2018 but we haven’t had really any difficulty executing trades in the closer years. Becca Followill And what did some other spreads look like relative to historical, are they already reflecting some pressure on that basis? Dave Bauer Well, the trade that we’ve done have generally than it a premium to NYMEX, obviously you go further out the liquidity discount gets to be a bit greater so for example in the near years we may be doing at a full year NYMEX plus 10 to 20 or so but then as you’ve move towards the 18 time period that roads to more NYMEX flat type level. And as you move beyond that, we do get indicative levels but the liquidity premium tends to increase quite a bit. Becca Followill Thank you. That’s helpful. On the well cost for Utica the 12 million that you’ve talked about the new well that you’re going to drill, what’s the depth on that in some of the early wells that we’ve seen, I know you’ve drilled a couple already but some of the early ones that we’ve seen from ECTE and coming in much, much higher than that? Ron Tanski Yes, depth for our Clermont Utica well is on the order of 10,500 feet true vertical depth. So it’s a little shallower. But I would say the bigger factor is that we’re drilling this on an existing Clermont Marcellus pad. So the infrastructures there its sharing pad cost with 10 other wells. Our water handling is all in place you don’t have to truck water from the long distance. So there is a big, big benefit to developing something like this as part of an existing development rather than one-off well that’s far from everything else. Becca Followill Got you. Thank you. And then will that 12 million include some of the normal science cost that happen with early wells to drive that up a little but higher? Ron Tanski Yes, there isn’t a whole lot of additional science in this particular well and I would also say that well cost estimate is probably on the conservative side. I hope we can do cheaper than that. Becca Followill Right, thank you. And then on the financing for 2016 the short fall of $500 million to $600 million, I know maybe you said you’re going to — right now in the plan it’s short term debt, at what point or what’s the timeframe if you’re looking to make a decision on whether or not you’ll financial it differently? Ron Tanski Well, as Ron said we’ve been evaluating NPL and other structures and as we move through the year and start to spend dollars on Northern Access, we’ll be announcing our definitive financing plans. Becca Followill The changes in what happened with NLPs lately and then downturn cause you in that anyway? Ron Tanski Well, not really Becca, we had just given the previous schedule we’ve talked about with respect to receiving the first certificate and when construction activity actually begin hasn’t changed. So we’ve got some time, obviously the market is going to do something, what it’s going to do we’re not sure, but we think no one is going to try to call a bottom here anytime soon but we may have already passed that, but that’s far enough out, that to talk about it in any kind of detail, would just to be able to bit premature. Becca Followill Understand. Thank you, guys. Operator We have no further questions. [Operator Instructions] We have another question and it comes from the line of Holly Stewart of Howard Weil Please go ahead. Holly Stewart Matt, maybe just one or two for you, several of your peers I guess have been talking about deferring completions as they’re heading into 2016 just to have that baseline of production growth and you’ve got quite a bit of volume curtail. But curious how you’re thinking about different completion as you kind of exit the year into ’16. Matt Cabell Yes so as I mentioned in my prepared comments at Clermont we drilled 52 wells, only completed 24. We expect to end the year — to end ’16 was about 50 wells that are drilled, but not completed. Although I think that number may include a handful that are completed and just not online at that time. Holly Stewart Is that in ’15 or in ’16 sorry? Matt Cabell The end of fiscal ’15. At the end of fiscal ’16 or best guess is about 65 wells that are drilled but not completed. Recognizing that with Northern Access 16 coming on at the end of the year we’ll probably have a fairly big slug of completion in that time frame just right after the end of fiscal ’16. Holly Stewart Okay so that kind of what bridge is that gap if you look at slide 18, I think it where it says the firm sales to future SE capacity and going from the 220 to 660. So that’s really what’s helping get you up to that rate as you enter into fiscal ’17? I’m assuming. Matt Cabell I’m finding the reference on the slide — you mean the gap between fiscal ’16 and fiscal ’17. Yes there is a big slug of completions for us. And the other thing that happens is we go from an assumption of some curtailments of spot volumes to not really having to curtail any more spot because we’ve got the firm transportation in fiscal ’17. Holly Stewart And maybe just kind of along the same lines, just kind of curious as your macro view. You’ve obviously got a lot shut in, but you also have from a spot fill standpoint, there’s the potential to shutdown lot more in 2016. So is there anything that you’re seeing out there as you look into your crystal ball and just ended 2016 from a Northeast PA standpoint, that there could be some pricing or release? Ron Tanski As we look at the projects coming on there is two projects that come on kind of late this year. Sort of the beginning of the winter that should de-bottle neck Northeast Pennsylvania to some degree. And our view is that winter spot pricing given normal weather and it may at least be acceptable such that we’ll be selling some spot this winter. It’s difficult to predict that Holly but there is our best guess. I would expect that that would be a winter phenomenon though, not necessarily for the full year. Operator Our next question comes from the line of Chris Sighinolfi from Jefferies. Please go ahead. Chris Tillett This is Chris Tillett on for Chris Sighinolfi how are you? Just a follow up on Becca’s question obviously the MLP has been on the lot of investors mind recently and given the kind of the turn-in in outlook in the market. I’d just be curious to hear your thoughts on some of the alternatives you’re considering and how you think about approaching this process in a non-MLP world. Matt Cabell I think if you obviously it’s a rather recent phenomena with respect to the MLP market. But I was thinking and really hasn’t changed all that much. And as I said it really would be premature to be talking about us pulling the trigger on any particular type of financing. Since we’ve given our schedule and given our timing we’ve have plenty of time to see how the market sort this self out. I guess that’s about all I’m prepare to say at this point. Operator We have no further questions. I would now like to turn the call over to Mr. Brian Welsch for closing remarks. Thank you. Brian Welsch Thank you, Halley. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 pm Eastern Time on both our website and by telephone and will run through the close of business on Friday, August 15, 2015. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010, and enter passcode 97670814. This concludes our conference call for today. Thank you and goodbye. Operator Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day. 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Great Plains Energy’s (GXP) CEO Terry Bassham on Q2 2015 Results – Earnings Call Transcript

Great Plains Energy Inc. (NYSE: GXP ) Q2 2015 Earnings Conference Call August 7, 2015 9:00 a.m. ET Executives Lori Wright – VP of IR and Treasurer Terry Bassham – Chairman, President and CEO Jim Shay – SVP, Finance and CFO Analysts Ali Agha – SunTrust Paul Ridzon – KeyBanc Shar Pourreza – Guggenheim Partners Brian Russo – Ladenburg Thalmann David Paz – Wolfe Research Operator Good day, ladies and gentlemen, and welcome to the Great Plains Energy Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. [Operator Instructions] As a reminder, this conference may be recorded. I would now like to turn the conference over to our host for today’s conference, Ms. Lori Wright. You may begin. Lori Wright Thank you, operator, and good morning. Welcome to Great Plains Energy’s second quarter 2015 earnings conference call. Today, Terry Bassham, Chairman, President and Chief Executive Officer; and Jim Shay, Senior Vice President, Finance, and Chief Financial Officer will provide an overview of our second quarter results. Scott Heidtbrink, Executive Vice President and Chief Operating Officer of KCP&L and Darrin Ives, Vice President, Regulatory Affairs are also with us this morning, as our other members of our management team who will be available during the question-and-answer portion of today’s call. I must remind you of the inherent uncertainties in any forward-looking statements in our discussion this morning. Slide 2 and the disclosure in our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations. I also want to remind everyone that we issued our earnings release and second quarter 2015 10-Q after the market closed yesterday. These items are available, along with today’s webcast slides, and supplemental financial information regarding the quarter on the main page of our website at greatplainsenergy.com. With that, I’ll now hand the call to Terry. Terry Bassham Thanks, Lori. And good morning everybody. As you saw in the 8-K that was filed yesterday, we are announcing a change in our officer team. Jim Shay will be leaving the company effective September 2 to take a new role as CFO at Hallmark Cards here in Kansas City. It’s truly been an honor and pleasure to work with Jim and we appreciate his leadership. Replacing Jim as Senior Vice President Finance, Strategy and Chief Financial Officer will be Kevin Bryant. Many of you know and have already worked with. Kevin is currently our Vice President, Strategy Planning and has been with Great Plains Energy for 12 years. His responsibilities at the company include Vice President of Investor Relations and Treasurer and Vice President of Energy Solutions. He is very eager to assume his new responsibilities and in particular working with each of you. I hope you’d join me to wishing Jim the best in his new opportunity and welcoming Kevin to his new role. On our call this morning, we will discuss our second quarter results and provide an update on KCP&L’s rate cases in Missouri and Kansas. We’ll also give an operations update and an overview of Transource’s new project in West Virginia. I will begin with Slide 4 in the presentation. Yesterday, we announced second quarter 2015 earnings of $44 million or $0.28 per share compared to $52 million or $0.34 per share in 2014. Drivers for the quarter included favorable operations and maintenance expense, positive weather normalized demand growth and milder weather with cooling degree days 15% below the second quarter 2014. We also reaffirmed our 2015 EPS guidance range of $1.35 to $1.60. Jim will discuss more details on the quarter in his comments. On the regulatory front, KCP&L’s rate cases are on schedule to be completed during the third quarter. In Missouri evidentiary hearings were completed in July and founder reply briefs were filed earlier this week. KCP&L’s initial request in revenue increase of $120.9 million was subsequently adjusted to $112.7 million as a result of updates to the case and negotiated partial stipulations and agreements. As a reminder, KCP&L’s request is based on a return of equity of 10.3%. Missouri Public Service Commission staffs recommended revenue increase ranges in the $76.8 million to $87.3 million predicated on our ROE range of 9.0% to 9.5%. The partial stipulations and agreements that have already been approved by MPSC resolved several issues in the case. The remaining unresolved items include ROE as well as the company’s ability to utilize a fuel clause and trackers for property taxes and critical infrastructure protection standards or CIPS cybersecurity expenses. In Kansas, evidentiary hearings concluded in June and reply briefs were filed earlier this week. KCP&L requested a revenue increase of $67.3 million based on a return of equity of 10.3. The Kansas Corporation Commission staff recommended a revenue increase of $44 million based on an ROE of 9.25. Turning to the Missouri case, we were able to resolve a majority of the issues in our Kansas case and partial stipulations and agreements were filed in June. The agreements include the ability for KCP&L to implement a transmission delivery charge rider and a CIPS cybersecurity tracker. Stipulations and agreements have yet to be approved by KCC. With most of these issues settled, ROE remains as one of the few unresolved items in the Kansas case. We anticipate new rates to be effective in both KCP&L’s jurisdictions by the beginning of the fourth quarter of the year. You can find summaries of the rate cases in the appendix of this presentation. We remain confident in our ability to deliver constructive regulatory outcomes in our current proceedings, reinforcing our commitment to deliver 4% to 6% earnings growth from 2014 to 2016. In addition, we remain on target to grow rate base to 6.5 billion by 2016. Turning to operations. Earlier this week, the Environmental Protection Agency issued the final standards for its Clean Power Plan. As we analyze the more than 1500 page document we are getting a better understanding of the plan and its potential impact. Although KCP&L and the electric power industry have spent more than a year working with EPA on a viable solution, the final version of the Clean Power Plan has significantly changed from the draft, we will continue evaluating the new rules. In recent months, our service territory has been impacted by the number of severe weather events, including a storm in late June that led to our largest customer outage since 2002. Storms uprooted or caused significant damage to over 50,000 trees, left over 150,000 customers without power. Our employees and our neighboring utilities worked diligently and safely to restore power to our customers, and I’d like to take this opportunity to thank everyone for their efforts and execution. I will wrap up with a few comments on transmission. We are pleased that Transource, our joint venture with AEP, was selected by PJM to develop the competitive portions of the thoroughfare area project in West Virginia. Construction on the 60 million 138 KV line is expected to begin in 2017 and to be in service in 2019. This win in the emerging competitive transmission market combined with its existing SPP projects reinforces our belief that Transource is well-positioned to successfully compete and deliver innovative solutions. I’ll now turn the call over to Jim to discuss our financial performance. Jim Shay Thank you, Terry and good morning everyone. I will begin with Slide 6 which presents a comparison of the second quarter and year-to-date earnings-per-share results for 2015 compared to 2014. As Terry indicated, our second quarter 2015 earnings was $0.28 per share compared to $0.34 per share last year. Lower operating and maintenance expense, positive weather normalized demand growth and new retail rates in Kansas were positive drivers that were more than offset by milder weather, decrease in AFUDC and increases in depreciation and amortization. For the year-to-date period, earnings were $0.40 per share compared to $0.49 per share last year. Through the first half of 2015, we’ve seen favorable O&M expense driven by diligent cost management and lower cost at Wolf Creek, related to the planned 2014 mid-cycle maintenance outage and lower refueling amortization. For the second half of 2015, we expect our O&M expenses to increase above the 2014 level. Consistent with our 2015 guidance, we expect overall O&M for the full year to increase 3% to 4% which include increases in regulatory amortizations and items which have direct revenue offsets. As a reminder, the O&M items with direct revenue offsets include our Missouri Energy Efficiency Investment Act programs. These investments allow us to invest in our customers by providing long-term energy solutions and ability to generate shareholder returns. We recover program costs and a throughput disincentive for these programs, which is included in our gross margin. Our projected O&M increase for the full-year 2015, exclusive of regulatory amortizations and items which have direct revenue offsets, is 1% to 2%. Turning to Slide 7. As we think about the third quarter compared to a year ago, we will be impacted by a decrease in AFUDC and increasing O&M. We will also expect continued lag from property taxes, transmission costs and depreciation until new rates are in effect. Lower natural gas prices are negatively impacting off-system sales, which have an earnings impact to KCP&L and Missouri, where we do not have a fuel clause. As Terry discussed, KCP&L’s ability to utilize a fuel clause is one of the remaining items to be determined by the commission in the Missouri rate case. A fuel clause would mitigate the exposure to off-system sales going forward. Finally, in the third quarter of 2014 we had unrecognized tax benefits that will have an unfavorable year-over-year comparison. As a result of these drivers, we expect third quarter 2015 earnings will be lower than the same period in 2014. Weather normalized demand, net of the impact of our energy efficiency programs, was up 1.2% for the quarter and up 0.6% year-to-date through June. The results are in line with our full year projection of flat to 1.5% net of energy efficiency. Year-to-date we’ve seen strong residential and commercial demand partially offset by lower industrial demand which has the lowest margin among the sectors. The Kansas City region has experienced 47 consecutive months of seasonally adjusted job growth and in June the unemployment rate of 5.3% was below the national rate of 5.5%. Construction is well underway at Cerner Corporation’s new Trails Campus in South Kansas City. The first two towers which will accommodate more than 3500 employees are under construction and a move-in date likely in early 2017. Over the next 10 years, a total of 16 new buildings containing 4.7 million square feet of office space supporting approximately 16,000 employees are planned, making it the largest economic development project in Missouri’s history. On the industrial front, we were impacted by a customer relocating to a more energy-efficiency facility within our service territory and a general decrease in usage from a handful of customers. Demand at Ford’s Kansas City assembly plant remains strong. Sales of Ford’s F-150 pickup truck had benefitted from gasoline prices that are near a five-year low. The Ford plant is operating with three shifts to keep up with demand for the F-150 America’s best-selling vehicle. On the capital markets front, we expect to issue long-term debt at KCP&L this year with no plans at this time to issue equity. We are reaffirming our 2015 earnings-per-share guidance range of $1.35 to $1.60. We are on plan to deliver on our financial objectives for the year and we remain confident in our ability to deliver 4% to 6% earnings growth from 2014 to 2016. Thanks for your time this morning. We would now be happy to answer any questions you may have. Question-and-Answer Session Operator [Operator Instructions] And our first question comes from Ali Agha of SunTrust. Ali Agha Terry or Jim, in the past, I had a call coming out of the last rate case cycle, you had mentioned that target earnings power for the company, should be between 50 to 100 basis point lag from the authorized ROE. Is that still a good rule to think about as we come out from this better [ph] rate cycle? Terry Bassham Yes, I think that’s what we’ve said all along, as the first year out of the case you should see that kind of range. Obviously what can affect your ability to deliver within that range, so it will be based on the outcomes of these cases. A few issues around riders and trackers and things like that. But certainly coming out as we did in the last cycle, the year after should be better matched to our historical test year. Ali Agha And then on the riders, trackers, fuel adjustment clause, any insights into how the commission may be looking at that, any sense of or conviction level in terms of the ability to get those this time around? Terry Bassham Well obviously we’re still awaiting an order, so probably little premature to have handicapped those. I would say that they remain very important to us. You can see some things that have happened in other cases that could indicate where they ruled on those before. But I will again remind you that we did get the CIPS tracker in Kansas and that’s a positive going forward for sure. We certainly – Commonwealth [ph] is expected to see those orders and rates implemented in this quarter. Ali Agha And assuming you do get those trackers and fuel adjustment clause, is it possible for you to hold on to that earned ROE in the following year like in ‘17 or is that just the natural lag in the way things work that you see some slippage as you go beyond the – on to the next year from the rate case? Terry Bassham Well obviously depend on which of the trackers, obviously we feel confident and think it important that we get the fuel factor itself in Missouri. There is a transmission piece and in the other asks we’ve made. Obviously if we’ve got all of the trackers, riders and asks we’ve made in that front makes it easier the second year, the extent you don’t get on this certainly makes it more difficult. What I would say to you is that if the — we don’t get those riders and trackers because they are considered general rate case type ask we will have to file rate cases on a much more frequent basis and we will do that. That was our response in this case with our prior asks and so what you’ll see from us if we are not allowed to deal with those in that manner is filing general rate cases much quicker. It’s just the nature of what we would assume is an indication from the commission. Ali Agha And lastly can you just remind us when you talked about the ’14 to ‘16 earnings growth outlook, can you just remind us what that base for ’14 is? Jim Shay It’s $1.60, off of the original guidance range. $1.60 was the bottom end of the original guidance range. Operator And our next question comes from Paul Ridzon of KeyBanc. Paul Ridzon Jim, congratulations on your new position and new role. I wish you the best of luck. It’s been a pleasure working with you over the years. Jim Shay Thank you. Paul Ridzon Quick question. How much of a headwind is not having the Missouri fuel clause? Terry Bassham Well, obviously it would be a disappointment and in the way we believe we’re entitled to it, it’d be a great disappointment candidly. In terms of actual financial effect, we already talked about the fact that we would have to file case again pretty quickly and at this point with off-system sales which are embedded in that being a very low level and an update on coal cost at the time it wouldn’t be a bigger drag as it historically has been. But it certainly would be one more challenge we’d have to face but we would again quickly file as appropriate ask for that in the next case. Paul Ridzon So just historically you had a fuel clause but you had to give it up as part of the deal. Is this how you treat, correct? Terry Bassham No, not really. Back in ‘04 when the original comprehensive energy plan was signed, there weren’t fuel clauses in Missouri. There was some discussed legislation that could create that. And so as we finalized the comprehensive energy plan and the deal, if you will, included gives and takes on both sides. It was agreed by the company not to ask for a fuel clause if and when legislation provided for that for our 10 year period. So that brings us to 2015 as our first opportunity to ask for it. Paul Ridzon And just on the transmission and property tax in Missouri, where does that stand as far as legislation or are you seeking more of a regulatory solution at this point? Terry Bassham Well again we’ve asked for both of those in the case. We will know again this quarter the result of that request from a commission standpoint, certainly if we’re not allowed to get those from the commission’s standpoint that would become part of our legislative agenda for the upcoming session. Operator And our next question comes from Brian Chen [ph] of Bank of America. Unidentified Analyst On the thoroughfare area project, can we get a sense of the spending pattern for that? Is there a ramp up as you sort of gear, should we think about even spending between now and ’19, just a little bit more color there would be great? Terry Bassham It will be about $60 million that will get spent from the period of from 2017 to 2019 would be the run rate. Unidentified Analyst And just as a clarification, the $60 million is the investment opportunity for Great Plains or is that the investment opportunity for the entirety of the project? Terry Bassham For the entire project. Great Plains will have 13.5% of that. Unidentified Analyst And Jim, hey congratulations on the new position. I’m just glad that I won’t have to potentially wear a Kansas Jayhawks tie again. Operator [Operator Instructions] Our next question comes from Shar Pourreza of Guggenheim Partners. Shar Pourreza Just one question, I am curious to get a refreshed viewpoint a little bit on sort of the requested ROE adjustment mechanism that Westar filed and obviously the staff recommended against it but also left it open for potential generic proceedings. I am curious to see if that’s something you would potentially look to go after with your Kansas utility? Terry Bassham Yes, I can mean, obviously each case presents its own issues and opportunities, that was a request from Westar that they left open, and certainly to the extent that there was a discussion on a more statewide level we would want to participate, work with both the commission and the staff and Westar to discuss that opportunity. Shar Pourreza Has conversations begun as far as the joint collaboration yet or is it too preliminary? Terry Bassham The cases they don’t file, settlement just happened. So we’ve been busy getting ready for this call. Operator And our last question comes from Brian Russo of Ladenburg Thalmann. Brian Russo Just curious if we could just talk some more about the lower gas prices and the sensitivity on the wholesale sales at the Missouri utilities. Could you just give us a sense of kind of like the total amount of wholesale sales in terms of megawatt hours, just kind of the mechanics of that, like what’s the base line that the sensitivity is based off of? Terry Bassham We don’t really have a lot of information in the public domain with respect to specifics but you recall in the last case we got offset of off-system sales established in rates and relative to over or under performance we will either get the benefit or give up an opportunity. And we have seen some pressure on gas prices this year which has been putting some pressure on off-system sales but in the upcoming rate case we will get a – we will get that trued up and hopefully a fuel clause and eliminate that volatility moving forward. But we really don’t have any numbers in terms of actual sensitivity in the public domain. And recall that the prices obviously were at lows, so I mean opportunity hopefully will be that they would tick up a little bit but – Operator I am showing a question from David Paz of Wolfe Research. David Paz I just wanted to clarify a statement I think I heard earlier. Can you remind me on the 4% to 6% growth target over the ’14-15 period? What is the base again? Terry Bassham It’s off of the original guidance for ’14 which is $1.60 to $1.75. So a pretty wide range using 4% to 6% growth rate off of that range. David Paz I thought I heard you say $1.60, I just want to make sure – Terry Bassham No, I was pointing to the bottom end of the range but the original – but the guidance target is off of the full range. End of Q&A Operator I am showing no further questions. I’d now like to turn the call back over to management for closing remarks. Terry Bassham Thank you, operator and thank you everybody for joining us this morning. We appreciate as always your participation in the call. Look forward to meeting with many of you in the weeks, months ahead. So thank you and have a good weekend. Operator Ladies and gentlemen this concludes today’s conference. Thank you for your participation and have a wonderful day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. 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WGL Holdings’ (WGL) CEO Terry D. McCallister on Q3 2015 Results – Earnings Call Transcript

WGL Holdings (NYSE: WGL ) Q3 2015 Earnings Conference Call August 6, 2015, 10:30 AM ET Executives Douglas Bonawitz – Head of Investor Relations Terry D. McCallister – Chairman, Chief Executive Officer, Chairman of Executive Committee, Chairman of Washington Gas Light Company and Chief Executive Officer of Washington Gas Light Company Vincent L. Ammann – Chief Financial Officer, Senior Vice President, Chief Financial Officer of Washington Gas Light Company and Senior Vice President of Washington Gas Light Company Adrian P. Chapman – President, Chief Operating Officer, President of Washington Gas Light Company and Chief Operating Officer of Washington Gas Light Company Gautam Chandra – Senior Vice President of Strategy, Business Development and Non-Utility Operations Analysts Operator Good morning, and welcome to the WGL Holdings’ Third Quarter Fiscal Year 2015 Earnings Conference Call. At this time, I would like to inform you that this conference is being recorded and that all participants are in a listen-only mode. We will open the conference call for questions and answers after the presentation. The call will be available for rebroadcast today at 1:00 p.m. Eastern Time, running through August 13, 2015. You may access the replay by dealing 1 (855) 859-2056 and entering pin number 91131626. I will now turn the conference over to Mr. Doug Bonawitz. Sir, you may begin. Douglas Bonawitz Good morning, everyone, and thank you for joining our call. Before we begin, I would like to point out that this conference call will include forward-looking statements under the federal securities laws. Forward-looking statements inherently involve risks and uncertainties that could cause our actual results to differ materially from those predicted in such forward-looking statements. Statements made on this conference call should be considered together with cautionary statements and other information contained in our most recent annual report on Form 10-K and other documents we have filed with or furnished to the SEC. Forward-looking statements speak only as of today and we assume no duty to update them. This morning’s comments will reference a slide presentation. Our earnings release and earnings presentation are available on our website. To access these materials, please visit wgl.com. The slide presentation highlights the results for our third quarter of fiscal year 2015 and the drivers of those results. On today’s call, we’ll make reference to certain non-GAAP financial measures, including operating earnings of WGL Holdings on a consolidated basis and adjusted EBIT of our operating segments. A reconciliation of these financial measures to the nearest comparable measures reported in accordance with Generally Accepted Accounting Principles or GAAP is provided as an attachment to our press release and is available in the Quarterly Results section of our website. This morning, Terry McCallister, our Chairman and Chief Executive Officer will provide some opening comments. Following that, Vince Ammann, Senior Vice President and Chief Financial Officer will review the quarterly results. Adrian Chapman, President and Chief Operating Officer, will discuss key issues affecting our business and the status of some of our principal initiatives. In addition, Gautam Chandra, Senior Vice President of Strategy, Business Development and Non-utility Operations, is also with us this morning to answer questions. With that, I’d like to turn the call over to Terry McCallister. Terry D. McCallister Thanks Doug, and good morning, everybody. I am pleased to be able to report to you that WGL is on track to deliver strong results and record earnings per share in fiscal year 2015. Our non-GAAP operating earnings for the first quarter is shown on Slide 3 in our presentation were $10.7 million or $0.22 per share compared to $0.8 million or $0.02 per share in the third quarter of 2014. On a non-GAAP basis, consolidated operating earnings for the first nine months were $159.8 million or $3.39 per share. This compares to $147.8 million in the prior year or $2.85 per share. The increase in operating earnings in the third quarter were driven primarily by strong results in our retail energy-marketing segment as shown on Slide 5. Our commercial energy systems and midstream energy services segments also reported improved results year-over-year. At the utility, our customer base continued to grow as average active customer meters increased by approximately 13,000 meters year-over-year for the third quarter representing a 1.2% growth rate. Regulated utility and its customers benefited from asset optimization results in the quarter. We also saw increased earnings in the segments from rate recovery related to our accelerated pipe replacement programs. On the utility regulatory front we received positive news regarding our recent filings to expand both our Maryland STRIDE and Virginia SAVE accelerated pipe replacement plan. We’re also excited about our announcement in May regarding an investment in gas reserves, serve our utility customers in Virginia. Adrian will talk more about these developments shortly. On the non-utility side of the business, as previously mentioned, our retail energy-marketing business performed well. With electric margins significantly higher than third quarter of last year. Here we have continued to execute plans that we’ve laid out on past call, we’re focused on large commercial and government accounts where longer term strategic relationships could provide additional value. Also, our pricing practices now include managing the risk of higher PJM cost. We forecasted at the end of 2014 that business has continued on the path back to historical levels of profitability. The result in this segment during fiscal year 2015 has exceeded our expectations and partly reflect specific market opportunities unique to this fiscal year. Over the long term, we’re still targeting adjusted EBIT for the retail marketing segment in the range of $50 million to $55 million per year. Given our results through the first nine months and our earnings outlook for the remainder of the year, we are raising our consolidated non-GAAP earnings guidance by $0.20 per share, to a range of $2.90, to $3.10 per share for fiscal year 2015. I’m now going to turn the call over to Vince, who will review our third quarter results by segment. Vincent L. Ammann Thank you, Terry. First, I would like to remind you that beginning with the first quarter of fiscal year 2015, we’ve made a change to our practice of discussing earning results at the segment level. While we continue to use operating earnings per share at a consolidated level, we are now using non-GAAP adjusted earnings before interest and taxes or adjusted EBIT to discuss results at the segment level. This change provides more clarity by allowing us to discuss the performance of each business unit, prior to the impact of interest expense, taxes and accretion and dilution. Turning first to our utility segment. Adjusted EBIT for the third quarter of fiscal year 2015 was $6.5 million, a decrease of $1.4 million compared to the same period last year. The drivers of this change are detailed on Slide 6. Higher results from our asset optimization program added $5.2 million in adjusted EBIT. Higher revenues from our accelerated pipe replacement programs added about $1.2 million in adjusted EBIT. The favorable effect of changes in natural gas consumption patterns in the District of Columbia added $1.5 million in adjusted EBIT. These items were offset by higher O&M expenses driven primarily by higher labour, marketing and employee incentives cost, partially mitigated by lower employee benefit cost. These impacts collectively reduced adjusted EBIT by $6 million. Higher appreciation expense also reduced adjusted EBIT by $1.9 million, reflecting growth in our investment and utility plan. Other miscellaneous items reduced adjusted EBIT by $1.9 million. Turning to the retail energy-marketing segment adjusted EBTI for the third quarter of fiscal year 2015 was $18.7 million, an increase of $13.7 million compared to the same period last year. On Slide 7, you will see that the increase was driven primarily by higher electric gross margins with higher natural gas gross margin also contributing. Electric margins increased by $9.9 million, mostly driven by lower capacity charges from the regional power grid operator PJM as well as slightly higher sales volumes. These positive benefits were slightly offset by increased PJM capacity costs that took effect in June 2015, which impacted the timing of margin recognition for fixed price retail contracts. Electric volumes increased 4% in the third quarter versus the prior year, primarily due to warmer weather and the recent growth in our large commercial market. As Terry discussed earlier, our retail energy marketing business, has increased its focus on large commercial and government account relationships. In the natural gas business, gross margins were $4.4 million higher, due to lower natural gas purchase cost and favorable gas supply and pricing opportunities. Natural gas volumes decreased 3% in the third quarter versus the prior year, primarily due to a decline in the mass market customers. This decline is also related to our increased focus on commercial and government account relationships. Next, I’ll move to the commercial energy systems segment. Adjusted EBIT for the third quarter of fiscal year 2015 was $7.8 million compared to $5.7 million in the same period last year. The increase reflects growth in distributed generation assets in service, partially offset by higher operating expenses. During the third quarter, our commercial distribution generation assets generated over 45,000 megawatt hours of clean electricity which was sold to customers through our purchase agreements. We remain on track to invest at least $150 million from commercial solar and other distributed generation projects during fiscal year 2015 with a potential to exceed that amount by 10% based on the timing of the projects in the pipeline. Next, I’ll move to the midstream energy services segment. Results for the third quarter of fiscal year 2015 reflect an adjusted EBIT loss of $1.4 million, compared to an adjusted EBIT loss of $4 million in the same period last year. The improvement is associated with storage transactions that occurred in this quarter. Results for our other non-utility activities reflecting adjusted EBIT loss of $1 million compared to a loss of $1.9 million, the same period of prior fiscal year. Improvement is primarily related to lower business development expenses in the current period. I’ll now move to discuss the interest expense on a consolidated basis to the third quarter. Interest expense increased to $13.1 million, during the third quarter compared to $9.5 million in the prior period. The increase was primarily driven by increased long term debt issued by both Washington Gas and WGL. As Terry stated earlier, we are increasing our consolidated non-GAAP operating earnings estimate as shown on Slide 8. We are forecasting non-GAAP earnings in the range of $2.90 to $3.10 per share. The increase is primarily due to strong performance at our utility and retail energy marketing businesses. Utility results are higher than expected, primarily due to asset optimization opportunities. On the non-utility side, we anticipate that excellent results on the retail energy marketing business will offset lower earnings from our midstream energy services business. I’ll now turn the call over to Adrian for his comments. Adrian P. Chapman Thank you, Vince and good morning, everyone. I’m pleased to provide you with an update on our operations and regulatory initiatives. In Maryland, we filed an application with the public service commission for approval of an amendment that expands our currently approved STRIDE plan. Washington Gas requested approval to add one additional program applicable to gas distribution system replacement and four additional programs applicable to transmission system replacements at an incremental investment of $31 million over the remaining four years of the STRIDE plan. This was our first inclusion of transmission pipe related replacement. On May 27, the chief public utility law judge issued a proposed order approving with modification the proposed amendment. Proposed order allowed accelerated recovery of cost related to transmission system replacements, located in Maryland, but excluded from the accelerated recovery program costs related to transmission system replacements, physically located outside of Maryland. This decision was contrary to how common transmission related costs have been recovered in rate case. Washington Gas appealed that portion of the decision to the full commission. On July 2nd, the PSC affirmed the proposed order, which approves an incremental capital expenditure of $18 million over the remaining four years of the plan. On July 30th, Washington Gas filed an appeal with the circuit court of Montgomery County to challenge the PSC decision to deny recovery through the surcharge mechanism of cost related to transmission system replacement projects located outside of Maryland. Notwithstanding the transmission related cost under appeal, we do have approval to spend an additional $4 million to $5 million per year on distribution and transmission replacements through 2018. In Virginia, we submitted an application to the state corporation commission in February, requesting approval to amend our current save plan to expand the scope of some existing programs to include new distribution facility replacement programs and to add new programs to replace transmission facilities similar to those proposed in Maryland. Washington Gas proposed investing an additional $75 million to replace, eligible infrastructure. The Company requested approval for the amended SAVE plan through December 31, 2017, which is the expiration date of the previously approved SAVE plan. On June 5th, the SEC approved the amended SAVE plan, however the commission excluded a small portion of the proposal to replace transmission facilities and the portion of the proposal to include new distribution facilities in the accelerated replacement program. The SEC in Virginia approved an incremental capital expenditure of $66 million through 2017, the new incremental billing factor which put in place on August 1st. Also in Virginia, a new law allows local distribution companies to recover a return of and a return on investments in physical gas reserves that benefit customers by reducing cost, price volatility or supply risk. On May 6th, Washington Gas entered into a 20-year agreement with Energy Corporation of America to acquire natural gas reserves through non-operating working interest in 25 producing wells located in Pennsylvania for $126 million. The purchase of the reserves is conditional upon approval by the Virginia SEC. Washington Gas filed an application with the SEC on May 12th for approval of the gas reserves purchase agreement, this part for the natural gas supply investment plan. Under the procedural schedule established to consider the application testimony from the Virginia SEC staff is due on August 26 and a public hearing is scheduled on September 30. Under the law, the SEC must issue a final decision of the application within 180 days or by November 8. Finally, I’m also pleased to announce that we’ve recently reached a new five-year collective bargaining agreement with the International Brotherhood of Teamsters, Local 96, that was effective June 1st and will continue through 2020. This contract, which covers approximately 520 employees strengthens our ability to work together with our unions to achieve excellence for our customers, investors and employees. I would like to now turn the call back to Terry for his closing comments. Terry D. McCallister Thank you, Adrian. I’d like to now highlight a few recent developments and provide an update over the status of our midstream and distributed generation investments. First, an update on our investments in the Constitution Pipeline project. We continue to wait for a permit from the New York State Department of Environmental Conservation. We remain optimistic that construction can begin in the next few months. As of June 6, WGL Midstream, had invested approximately $26 million on the Constitution Pipeline project. Next, I’ll turn to our investment in the Central Penn line. The Central Penn line is a greenfield pipeline segment of Transco’s Atlantic Sunrise Project. This project is on track and the development activities are proceeding as expected. The Central Penn line has a projected in service date in the second half of calendar year 2017. WGL Midstream will invest approximately $412 million in the Central Penn line project. As of June 30, our subsidiaries had invested approximately $22 million. Next I’ll provide an update on our investment in the Mountain Valley pipeline project. Mountain Valley pipeline is a 300 mile pipeline in West Virginia and Virginia, and will help meet the increasing demand for natural gas in the mid-Atlantic and Southeast markets. The project is on track and development activities are proceeding as expected. Mountain Valley pipeline has a projected in service date in the second half of calendar year 2018. WGL Midstream will investment between $230 million and $245 million on the Mountain Valley pipeline project. As of June 30, WGL Midstream has invested approximately $6 million. Finally, an update on additional opportunity to invest in infrastructure that we first announced last December. As we discussed with you previously, we have an option for a 30% interest in a $400 million plus gathering system in West Virginia. This gathering system will help move gas out of production field to West Virginia to an interstate pipeline system where transportation to the mid-Atlantic region. The anticipated in-service date is now late 2015 or early 2016. We continue to evaluate additional midstream opportunities similar to the projects announced to date as we pursue our strategy to provide infrastructure solutions to move gas from producing areas to consuming areas. Turning to our commercial energy systems business, we continue to add our portfolio of distributed generation assets. As of June 30, we have 115 megawatts of installed distributed generation. We also have an additional 40 megawatt currently under contract or in construction. In total, these projects represent over $520 million in capital investment and we continue to see a robust pipeline of future projects. I want to highlight one solar project in particular this quarter as it represents our first project in the State of Colorado. WGL Energy Systems recently signed an agreement to build and operate a 1 megawatt solar project in Fort Collins, Colorado. The project is expected to be in service by December 2015 and WGL Energy Systems will own and operate the solar project for 20 [ph] years as per our agreement. In July, Washington Gas celebrated the opening of the first of three plans public CNG fuelling stations for compressed natural gas vehicles. The new station located at Washington Gas facility in Frederick, Maryland will be operated and maintained by Trillium CNG. Later this summer Washington Gas and Trillium expect to open a second public fuelling station in Forestville, Maryland and a third station is being planned for the District of Columbia. We’re proud to add this service to the spectrum of energy answers we offer at WGL. In addition, WGL Energy Services, recently teamed up with SolarCity to offer our residential customers in Maryland, Delaware, Pennsylvania and the District of Columbia the opportunity to choose clean, renewable energy by installing a custom-designed solar energy system. Through this innovative marketing partnership our customers in these areas may now choose to install a SolarCity solar system at no upfront cost and pay less than traditional electric utility bills. This residential solar option will complement our existing operating business segment which includes wind power for electricity and carbon offsets matched to natural gas usage. We will provide detailed fiscal year 2016 guidance during our year-end conference call in November. However, based on the progress we’ve made in a number of important areas we feel confident and we’re on track to deliver the earnings growth goal in our long-range financial plan. That concludes the prepared remarks and we’ll now be happy to answer your questions. Question-and-Answer Session Operator And our first question comes from the line of Michael Gallagher. Michael Gallagher Congrats on the really strong quarter. I’ve only got two questions. First, the performance from retail marketing was impressive. Just wondering, how we should think about fiscal 2016. Are these results sustainable or are they a potential headwind next year? Vincent L. Ammann Michael this is Vince. We’ve provided some guidance there, that there were some market opportunities that we saw this year that allowed us to really exceed our expected results, probably even exceeding the long term goal of $50 million to $55 million certainly at the high end of that range. So, we’re probably looking at a 2016 that will be slightly less than what we’re able to achieve this year. Gautam, if you have anything more to add? Gautam Chandra Yeah Michael, I will just add, I think we’re still looking at what we initially kind of projected. And a couple of years ago, we’ll bring this headwind back to its historical level, the $50 million to $55 million, we still see that as very achievable, going into next year, but probably not. I wouldn’t forecast the additional margins we would realize this year into next year. Michael Gallagher Then on Central Penn, I’m wondering if you’ve determined yet where the interconnect is going to be in Southern Pennsylvania. Vincent L. Ammann I think we have a pretty good idea, but I don’t think the partners have announced that yet. Terry D. McCallister Yeah, I don’t think that’s public information yet. Michael Gallagher Okay, that’s all I had gentlemen. Thanks. Operator [Operator Instructions] Again, I would like to remind everyone that you can listen to a rebroadcast of this conference call at 1 p.m. Eastern Time today, running through August 13, 2015. You may access the replay by dealing 1 (855) 859-2056 and entering your pin number 91131626. Douglas Bonawitz Thanks everyone for joining us this morning. If you have any further questions, please don’t hesitate to call me. It’s Doug Bonawitz at (202) 624-6129. Have a great day.