National Fuel Gas Company (NFG) Q2 2017 Earnings Report, Transcript and Summary

Good morning, my name is Virgil and I will be your conference operator today. At this time, I would like to welcome everyone to the National Fuel Gas Company Earnings Conference Call. [Operator Instructions] Thank you. Brian Welsch, Director of Investor Relations, you may begin your conference.

Thank you, Virgil, 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, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The second quarter fiscal 2017 earnings release and May Investor Presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. We would 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. National Fuel will be presenting at the American Gas Association Financial Forum later this month in Orlando March. If you plan on attending, please contact me directly to schedule a meeting with management. And with that I'll turn it over to Ron Tanski.

Thank you, Brian. Good morning everyone. I just saw on our earnings release last evening we have another strong quarter both financially and operationally. In our upstream exploration and production business, commodity pricing in Appalachia has improved to the point where since October none of our producing wells have been shut in due to pricing. As a result, our produced volumes have been trending at the high-end of the range of our production guidance which is helped drive earnings higher in our exploration and production segment and our gathering segment. So I will give a little more detail on our near-term production marketing plans that we expect will allow us to continue our production trend at the higher end of our guidance range for the rest of the year. The higher earnings in our upstream and gathering businesses offset the slight declines in the earnings of our other business segments and Dave Bauer will give more detail on the earnings drivers in those segments later in the call. Overall, our operating folks are doing a great job in all of our business segments. Seneca continues to be a leader in keeping down drilling and completion costs in the Marcellus. And our gathering pipeline folks continue to be ready with the pipelines that can take production to market as soon as each well pad is completed. In the transmission pipeline business, we've been successful in securing new offtake business on our Line N system in Pennsylvania to service a new load for the shell cracker plant that is now under construction. Last evening we commenced an open season for yet another 215 MMBtu expansion in Pennsylvania for end-use markets on our Line N system. In addition, we were successful in signing up and anchor shipper for the base load capacity on our Empire North project and look to get some additional precedent agreements in place for the remaining capacity over the next quarter. In our Utility business, recent audit commissioned by the New York PSC indicate that across many of the metrics studied, National Fuel is the most efficient utility in the state and our rates are the lowest of any of the major utilities in the state. Again, operations in all our business segments have been going great for a long time. That's the old news. The current news is that we're getting lousy regulatory treatment in New York State. Early last month an executive branch agencies stimied our attempt to invest $0.5 billion in a federally approved pipeline project that would help us grow the company and assure continued strong presence in the state. Contrast that situation with conditions in Pennsylvania where we are continuing to expand our infrastructure for new businesses that are moving in and growing by taking advantage of plentiful domestic energy supplies. Later last month, another New York executive branch agency issued an order in our Utility rate case that awarded our utility, a rate of return on equity that is the lowest granted in the state and in the entire country since at least the 1980s when a consulting firm starting keeping track of utility rates of return across the U.S. Given this type of regulatory treatment in the state, we have to take a serious look at our ability to achieve any reasonable growth in New York. As we pointed out many times however, our diversified business model provides a number of growth opportunities for us not necessarily tied to just one state. For the immediate future, we'll focus in areas where we can grow while our lawyers are busy with the DEC in the Second Circuit. With respect to that lawsuit, unless we are able to negotiate a resolution, we expect that our litigation will take a minimum of one full year to resolve but likely longer. Assuming a timely resolution and the need to re-mobilize all of the engineering and contractor logistics surrounding the Northern Access Project, we’ll be looking at an in-service day in either the spring or fall of our 2020 fiscal year. Keeping with our normal practice, we won't be issuing guidance for our 2018 fiscal year until next quarter but given the timing changes related to Northern Access we thought it would help to give some preliminary perspective on the forward trajectory of our capital spending, our growth prospects and financing needs. Until there is greater clarity around Northern Access, Seneca will continue to operate a two rig program in Appalachia, with one rig dedicated to the Claremont Rich Valley area and another splitting time between Tioga and Lycoming County's. A single frac crew will handle completions. At this level of activity, Seneca should be able to grow production by at least 10% CAGR over the next 3 to 5 years even without Northern Access. Pricing in the basin and our success in locking in acceptable returns will dictate our ability to achieve this growth. To that end, we continue to pursue a combination of financial hedges and physical firm sales to create a degree of price certainty for our program. Recently, we've been particularly focused on adding new firm sales at Claremont Rich Valley and converting the delivery point of previously executed gone-based firm sales to TGP 300. Thus far John and his team have been successful at both. For example, some recently executed deals for fiscal 2018 have been executed and realized fixed prices that exceed the netback price we would've achieved via deliveries to Don. We’ve also been focused on adding firm sales tied to our production from tract 007. We don't hold any firm capacity on the TGP 300 line that runs right through that acreage, so our goal is to build a long-term base of firm sales in the neighborhood of 100 to 125 MMBtu per day. To date, we've added 45 MMBtu per day of new firm sales at tract 007. In the near-term, we expect Seneca will live within cash flow as under its two rig program. Longer-term as we grow our production days, Seneca has the potential to generate significant free cash flow. Under Seneca's revised program gathering capital should be relatively modest especially if Seneca transitions to a Utica program in the Western development area and it can effectively reuse existing infrastructure. Given the expected growth in Seneca's production, a gathering business should generate significant free cash flow over the next three to five years. In the pipeline and storage business, we expect that the recent New York DEC permit interpretations will not interfere with our normal maintenance and system modernization activities or annual capital requirements should be in the neighborhood of $100 million. An expansion projects like Empire North, always caused bumps in that baseline rate. At the Utility, capital spending over the next several years should be consistent with our current $90 million to $100 million a year level. On a consolidated basis, until we undertake any expansion projects, annual capital spending will likely be in the $500 million to $600 million area. At that level of spending, we should be able to generate consistent growth across our portfolio of assets, deliver long-term free cash flow, maintain our commitment toward dividend, and further improve our balance sheet. Those of you that know our assets, know that we have thousands of drilling locations across our acreage position that could support an even higher growth rate. While basin pricing has improved, we still believe there is a need to reach a major liquid market to deliver significant growth that the local markets cannot absorb. Northern Access is still the best path to deliver that next leg of growth and we remain committed to developing it. I’ll turn the call over to John McGinnis to cover Seneca's operations.

Thanks Ron, and good morning everyone. Seneca enjoyed another solid quarter. Natural gas prices remains strong in Pennsylvania and as a result we had no price related curtailments during the quarter. Seneca produced 45.6 Bcfe during the second quarter, an increase of 6.4 Bcfe or 16% versus the prior year second quarter. In Pennsylvania, we produced 40.8 Bcf for the quarter, an increase of 6.7 Bcf or 20% versus the prior year. This increase was driven by stronger than expected Marcellus well performance and no curtailments due to continued strength in the spot market. Therefore, we are again increasing our production guidance for the year to now range between 165 to 180 Bcfe, an increase of 7.5 Bcfe at the midpoint from last quarter's guidance. Since Northern Access was not plan to be operational until fiscal '18, there will be no immediate impact on Seneca's fiscal 17 activity level. As planned, we added a second rig this month and it will begin drilling in Lycoming as we prepare for our Atlantic Sunrise capacity mid-2018. The rate will then move to a DCNR 007 tract in Tioga County to begin a Utica development program. Our Utica appraisal well in Tioga continues to outperform expectations, and this well has now produced over 2 Bcf in less than six months. Based on the strength of this well, we believe we have around TCF of potential resource within the Utica on this tract. We have decided to accelerate our 007 Utica drill program and this will be an area of significant production growth over the next few years. First, production from this program is now forecasted to occur in early fiscal '19. Our current rig will remain in the Western development area drilling both Marcellus and Utica wells over the next 18 months with the intent of finalizing both our IOG joint development program and appraisal of our Utica potential by mid next year. Our two WDA Utica wells have now been online for over four months and we are raising the EUR per thousand feet for both of these wells to range between 1.8 and 2 Bcf. Though these wells do not have large IP rates, they have experienced very low decline rates that had been shallower than our typical Marcellus wells in the area. Two additional Utica wells were brought online in April and we will discuss results once these wells have cleaned up and have been producing for over 30 days. Our fifth Utica well is scheduled to be brought online next month and we have accelerated the completion of three more Utica wells into this fiscal year. This shift forward related to our Utica activity will increase our fiscal '17 capital expenditures but will effectively reduce our fiscal '18 spend since the completion of our final 12 joint development wells will be pushed into early 2018. We are raising our CapEx guidance for the year to range between $210 and $215 million, an increase of 30 million at the midpoint. Once we have sufficient production history from our WDA Utica wells, we will then decide whether or not to shift to an exclusively Utica drill program over the next few years. Spot prices in the basin have improved dramatically over the past six months averaging between $2.50 to $2.65 at each of our receipt points. The opportunity to layer in fixed-price sales at attractive pricing has also improved and as a result we are now active in the market layering in firm volumes over the next two years in each of our key areas. We expect further basis improvement as Rover and other pipeline projects in the basin at around 4 Bcf per day of new transmission capacity by the end of this year followed by Atlantic Sunrise mid-2018. However we feel that improved pricing within the basin will most likely be short term anywhere from 3 to 5 years. In order for Seneca to achieve significant long-term production growth we will need the ability to access a major liquid market. In our view Northern Access remains the most affordable and simplest route into an attractive market. At a two rig pace, our average annual production growth over the next few years should range between 10% to 15%. If prices within the basin remain strong and differentials continue to tighten however, we will seriously evaluate the addition of a third rig. In California, we produced just under 800,000 BOE's, a 6% decline from last year second quarter. Much of the decline has occurred at North Midway sunset which is down around 600 barrels per day from the year ago. This is due to a number of reasons in part from natural decline but also from reduced drilling and workover activity over the last couple of years due to lower pricing. Also in response to lower pricing, our focus has been on steaming the most productive area of the field. As pricing has improved we have increased our total steam volume and we are now reallocating steam back into these areas that had cooled. As we move forward, we expect to arrest this accelerated decline in return to production trends somewhere to a year ago. At South Midway Sunset, we are already seeing an impact as a result of our 2017 drill program. Production in this field has increased 200 to 300 barrels per day to a total of 2100 barrels per day. South Midway has been a great addition to our California property base. When we acquired this asset back in 2009, total production was only 550 barrels per day. Today South Midway is producing at almost four times that rate. Immediately adjacent to South Midway, we have just returned 11 wells to production and have drilled four wells at our new pioneer development area. We have recently started injecting steam into this area and expect oil production to start increasing over the next several months. And with that, I’ll turn it over to Dave.

Thanks John, good morning everyone. Putting aside the regulatory challenges Ron outlined earlier, the second quarter was a good one for National Fuel with earnings up $0.07 per share over the last year. The quarter also highlights the benefits of a diversified business model as the outstanding performance of our non-regulated operations more than offset a modest dip in our regulated businesses. Seneca had a great quarter with significant improvements across the board. Net production in Appalachia was up nearly 20% which contributed $0.15 to Seneca's earnings and was the main driver of our gathering businesses $0.03 per share increased in earnings. Spot prices in Appalachia were strong averaging approximately $2.60 per MMBtu not more than a $1.40 over last year. Lastly, Seneca saw a significant improvements in per unit operating expenses with combined DD&A, G&A and LOE down 20% versus last year. In addition to being lower than the prior year's amounts these costs all came in towards the low-end of the range of our previous guidance. All in, it was a terrific quarter for Seneca with recurring earnings nearly doubling over last year. Going in the other direction, Utility earnings were down $0.08 per share compared to last year. A large portion of this decrease was attributable to our new customer billing system which as we discussed on prior calls increased both depreciation and personnel related expenses. We began recovering a portion of these costs in our New York division when new rates went into effect on May 1. Also contributing to the decrease in earnings was warmer weather in the Pennsylvania division of our utility and higher pension expense. In the pipeline and storage segment, earnings were down $0.03 per share largely because of lower revenues. This decrease was not a surprise, most of it was due to scheduled rate reductions we had agreed to in prior settlement agreements at both supply and Empire. However, given the warm weather and relatively flat pricing basis across our pipeline system, we did see a bit of a drop in short-term transportation revenues relative to forecast during both the first and second quarters. As a result, we now expect revenues in the segment to total between $295 million and $300 million for the full fiscal year. Lastly earnings at National Fuel resources are nonregulated energy marketing company were down $0.03 compared to last year. Like Seneca, NFR is at risk for pricing basis. It makes the bulk of it sales at a fixed discount to NYMEX. However, the stronger pricing in the basin that benefited Seneca had the opposite effect on NFR where higher-than-expected purchased gas costs squeezed its gross margin for the quarter. Looking at the rest of the year, we’re increasing in tightening full-year earnings in production guidance ranges. Our new earnings guidance is $3.20 to $3.35 per share. This increase reflects our strong second quarter performance and several other factors including Seneca's updated production forecast which as John mentioned earlier is now 165 to 180 Bcfe. As in prior quarters, the 15 Bcf range reflects the potential per pricing related curtailments. The low-end assumes we curtail 100% of our spot production to the last five months of the year while the high-end assumes we have no curtailment. This makes our production guidance fairly conservative. Should we continue to produce without curtailment, it's likely that our production will be towards the high end of the range of our guidance. Our NYMEX pricing assumptions are unchanged at $3.25 for gas and $55 for oil. Oil is traded off a fair amount but we are well hedged. For the remainder of the fiscal year and assuming the midpoint of our production guidance we are about 80% hedged for natural gas, and 60% for oil. Therefore any changes in commodity prices should have a relatively modest impact on our cash flows. As a frame of reference, a $5 change in oil equates to about $3 million and EBITDA of $0.02 per share. Given the strong pricing in Appalachia, we are up in our spot price assumption for the remainder of the year to $2 per Mcf, a $0.50 increase. Again this is an area where we hope we are being conservative. Recent pricing in the basin is average closer to $2.50. In fact, today's pricing is in the $2.60 to $2.80 area. We made some small refinements to Seneca's per unit operating cost assumptions that you can see on Page 5 of last night's release. You’ll note that full-year LOE is expected to range between $0.95 and a $1, somewhat higher than the $0.91 per Mcfe rate for the first six months of the year. This increase is due to higher spending at Seneca's California operations where we recently commenced steaming operations on our latest farm-ins at Midway Sunset. These are particularly timely expenditures given the availability of a federal tax credit for these activities. Our assumptions with respect to the rest of the regulated businesses are generally consistent with our prior guidance. The only change of significance was at the pipeline and storage segment where the delay in Northern Access caused us to remove about $0.03 per share of AFUDC from our forecast. Our updated guidance reflects the recent order in our New York rate case. From an earnings standpoint that order was generally consistent with the recommended decision issued in January. New rates went into effect earlier this week so with the heating season behind us, there won't be much of an impact on fiscal '17 earnings. Going forward on a full-year basis, assuming 704 million a rate base and 8.7% ROA and 43% capital structure, the rate award equates to about a $0.05 per share impact on earnings. Our updated consolidated capital spending for fiscal '17 is the range of $450 million to $530 million at the midpoint down 100 million from our previous range. Substantially all the changes are related to the delay in the Northern Access project which reduced plan pipeline and storage spending by $115 million. Combined to E&P and gathering CapEx is higher by $15 million due to changes in the time you're spending between fiscal years. There is no change in the overall level of activity. At this level of spending, and including our dividend, I expect we’ll live within cash flows in 2017. While we certainly prefer to be building Northern Access, the delay in the project will strengthen our balance sheet in the near-term. Our next long-term debt maturity is in April of 2018 and the ultimate timing of Northern Access will determine when we’ll finance those bonds. With that, I’ll close and ask the operator to open the line for questions.

[Operator Instructions] Your first question comes from the line of Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen. Ron, maybe the first question is sort of bigger picture, thinking through Constitution and their appeal. How would a decision, which, I think, is expected in the next few months, impact you guys just positive or negatively on the process of your appeal for Northern Access?

Well, that's interesting, Holly, because the denial in constitution at least appeared to be on the basis that they did not present enough information. So it's hard to say where the court will come out on that. Ours on the other hand was based on all the information that we did submit, and they thought that impacted the water quality of the state. Now, who knows, it seems to be a moving target given that the DEC just permitted Algonquin to install 42 inch pipeline is in the same construction methods that were deemed unacceptable for our project. I mean it just indicates how arbitrary the decision-making can be. So it’s hard to say what the constitution decision could mean for us. We're all scratching our heads here right now to say the least.

No absolutely, maybe an extension on that. I know you think Northern Access is the best foot forward. Any new thoughts on Nexus? Any maybe ultimately like they still have some capacity- taking this capacity on that project.

Yes. We’ve talked about other routes before our plan B. Right now our plan B seems to be working out just fine with respect to getting fixed price sales in the basin. That frankly have improved because of the rover and the installation of other outlets for production in the basin. So I mean that’s the immediate Plan B. But, yes, our engineers are looking at ways to expand pipelines across Pennsylvania through our WDA, possibly west for interconnection there. But as we’ve stated before, you get into the situation of pan-caking additional rates and that will affect the ultimate economics of our drilling in the WDA.

Okay, great. And then, maybe one for John, just on the new 10% 3-year CAGR that you hit out. Can you maybe just talk about the kind of embedded assumptions with that, whether it's rig count or wells to sales, or kind of how you guys are coming up with that growth rate?

Sure. Obviously we've done a number of forecast based on the two rigged case. We’ll talking about that next quarter when we at least put out our fiscal '18 forecast. But from a big picture, with respect to '18, since removing the completion of 12 of the joint development wells into next year, and because we’re just now adding the second rig this month, I don't see or I don't think we'll see annual production growth significantly above 10% next year. Having said that moving into the fiscal '19, Atlantic Sunrise will be on the entire year. Our Tioga Utica production should be ramping up in Q1, Q2 of fiscal '19 and we’ll be bringing online many more a 100% working interest wells in the Western development area. So I see, at least in '19, I could see that we could - it will be 10, at least 10 if not greater than that.

That’s great. Thanks, guys.

Your next question comes from the line of Graham Price from Raymond James. Please go ahead.

Hi guys, good morning, and thanks for taking my question. So looking at Slide 26 of the presentation, it looks you’ve done a great job layering in the current sales contract so far as. I was just wondering if we could get a little more color on what the landscape looks for bearing in even more contract going forward?

Absolutely. We’ve been very active in the market. As Ron said in his section of the earnings release, we've already layered in an additional 45 million a day, a double of seven development program. We are actively layering in fixed sales, firm sales at Clermont Rich Valley. But mostly focusing on fiscal '18. And over the next few months, we’ll begin to push that into layering in fiscal '19 and '20 volumes as well. The market has been fantastic. We’ve been able to get prices that we feel will generate a rate return of 30+ on all of our development programs. So we think that at least for the next 6 to 12 months that this is going to be an active market, and we’ll have plenty of opportunity to close that gap that you see on that slide.

Okay, perfect. That sounds very positive. And for a quick follow up, we’re just wondering if there is anything specific that you could point to regarding that UR up with the Utica wells that you mentioned.

The decline has been a lot less than we anticipated. We’re comparing these wells to some of the decline curve that we see through Potter into Tioga, and the two wells that we have online -- now it’s only been four months, so we still have a ways to go. But the decline is just been a lot less than we’ve seen in other areas. That's what driving the increase.

Thanks guys.

Your next question comes from the line of Tim Winter from Gabelli. Please go ahead.

Good morning and thanks for taking my question. I was wondering if you guys had any recourse regarding Northern Access with FERC to perhaps supersede the state.

Yes, Tim. If you read the back and forth that we already had with -- not back and forth with FERC, but our filings with FERC and then response by the New York TEC with respect to that. Yes, I mean, we think there is a possible avenue for preemption by the FERC or through the FERC process. Unfortunately in order to achieve that, FERC has to get back up to a quorum which we expect won’t be happening until probably late summer, early summer, maybe late summer for them to be able to do that. But, yes, I think I mean our arguments were quite clear in the paperwork that we filed with FERC with - on hearing. So, yes, that’s absolutely a path.

Okay. And then back to the New York Public Service Commission. What is your regulatory strategy going to be going forward? Are you going to be maybe refile or just sort of stay away?

Obviously, the cost pressures or an increased investment as a result of our modernization programs will always have us looking at the possibility of a new case. As we pointed out in the 10-Q that we just filed or will file later on. We’re also looking at a possible appeal of that decision with respect to the disparate treatment that we received versus other utilities in the state. So any number of avenues to look at there. Overall, we’re going to continue our practice of providing the best service to our customers in the state, and watching costs as we do that as a result. That’s why we’ve been able to achieve the lowest rates as I mentioned before any of the utilities in the state. So we've obviously got a business to run as I said before we think it's a lousy decision but we’ll continue to operate and do the best we can.

Okay, great. Thank you and congrats on the quarter other than the regulatory treatment.

Your next question comes from the line of Chris Sighinolfi with Jefferies. Please go ahead.

Hi, good morning guys. Ron thanks for the color, I wanted to maybe at least picked up where Tim left off just on the regulatory climate I mean, clearly I've been following it quite as long as you have and it certainly seems like we taken a couple of steps back in the last couple of years culminating with the things that you talked about the 401 permit analysis and constitution on your own project, the NFGB decision. lowest authorized ROE of any gas utility in decades. I guess I'm just wondering it seems like it's no very political agenda which is produced those I guess but leading politics aside and just thinking about from a business perspective. I guess I have a couple questions, first it seems like you agree with that assessment given the commentary you also had prepared remarks I am just wondering how you and Dave and the board think about how that shapes your capital allocation decisions around New York investments. And then second just given that you do have other businesses within national fuel which exist outside of New York how it sort of shapes the relative trade-off the regulatory risk issues in New York and then just I guess wondering if there is any potential divestiture opportunities of your New York businesses?

While there is a number of the questions in there Chris, so let me try to tackle it. If you look any historical period and then let's look back over say five to nine years and over nine years we've invested over $6.2 billion in all of our businesses through the years 14% to 16% of that was invested in New York and over the same timeframe 74% - 77% was invested in Pennsylvania with our Northern Access project we were looking at a substantial increase investment in New York State. And let’s be clear we still love to achieve some sort of a negotiated solution for that project but when the governor won't take 10 minutes to respond to repeated requests of the CEO of New York headquartered company with 1,200 employees in the state and the commissioner of the DC won't return my calls I mean who are we going to negotiate with. So since it appears that our growth investments are not necessarily welcome percentage of investments in New York will continue to decline. Now as I said before we’ll continue to make investments in our pipelines to make sure they're safe I've already gone through those numbers before but our growth capital will be continue that with Seneca in Pennsylvania and California and incremental pipelines are likely avoid New York. Now you might find a counterintuitive that we would consider investing more in California for environmental regulations are just as or maybe more stringent than New York. But in California the regulations are consistently interpreted and we know what to expect.

So again it’s New York will probably decline and the real question gets to be whether we’ll be able to attract capital and the usual investors for a long-term debt our insurance companies that are risk-averse and by directing our investments to areas that are more predictable, we think the capital markets will be fine when we visit them. So I’m not sure that that answer your question but it’s kind of generally where we see things going.

No I mean itself helpful I think we’ve seen parallel cases this is probably going back a decade with some of the companies active in states like Arizona and working commission structure there was like the end predictability of outcomes led to their decisions to invest heavily in other regions so I was assuming the answer was going to be similar for you that just helpful to hear from you directly on it. I guess switching gears a little bit and extrapolating from I think you had mentioned or David mentioned sort of $500 million or $600 million your consolidated CapEx run rate number in your plan sort of excluding any lumpy expansion related capital needs. I guess on our modeling that suggests free cash flow over the next several years. So I'm curious with a credit ratings where they are with that cash flow profile the appetite to expand the footprint in areas outside New York that may be present greater growth avenues but I don’t know if M&A would feature in that if there is something we could discuss that might be on our wish list. And then this has been a very long time since you discussed Ron but your buyback program I think you still have like 7 million shares authorized via your purchase. At what point does that maybe come back into - could be something which you consider?

I think with respect to the buyback, we’ve obviously always been watching that’s been out there since I think 2007 obviously we stop that during the capital markets issues in 2008. But we do have that available I guess we prefer again always rather than shrinking the company prefer to grow the company and having some dry powder for opportunities that frankly come up on a regular basis on the expiration of production side and we were always looking at things as you can imagine. Our history has been all across the natural gas value chain and what we'd love to have more pipeline investments that you can serve a dual purpose to grow the company it doesn't appear that that's going to happen anytime soon in New York, but we’ll still push obviously as I said in the prepared comments Northern Access everything makes sense from a number of point of view it’s from energy security in the state to helping grow the New York headquartered company, that’s makes a lot of sense. But if we can't we’ll be looking at things likely across Pennsylvania or in and it always as we've looked at M&A on the utility side. It's always been a joining service territories that make the most sense where you can achieve the most synergies and extract costs and higher earnings from. So we’ll be looking at that, but given where the multiples are these days I’m not particularly aware of any imminent opportunities on the utility side.

Okay. Really appreciate the color, I guess one final question for me and just switching gears and for John and there was familiar question on it. But I just wanted some help in how we think about, you know the process of converting those Dawn firm sales contracts and basing contracts, you've mentioned the new contracts you’ve added. And I realized this whole process is similar to what you did couple years ago when you voluntarily delayed Northern Access but I guess two questions one the dynamics on t how you do the conversions. And then second how deep is that market your comments about the needing an evacuation or physical exam route is what would sort of underpin meaningful long dated growth Seneca. So how do you run a program depending how deep from sales agreements with that can we sign 2020 right now or is the market just not there for?

Actually the market is there a lot of our firm sales that we've been layering in at 007 for our Utica development in Tioga most of those are three to five year contracts the terms are. So it's there the market is there to layer in those kind of at least those kind of terms. As far as converting Dawn-based firm sales back to CRV we've been actively doing that for a number of months. We've done it I think 100% through March of next year and actually it's a pretty good time to be doing it and honest slipped a little bit we converted to NYMEX and then layer in a basis differential off of NYMEX at our at our, Clermont/Rich Valley receipt point. So it's actually we’re seeing some pretty good prices so we will be aggressively trying to get that done over a multiyear term over the next month or two. The only thing we need to be careful of a little bit as Tennessee is a very large pipe it moves a lot of gas every single day. The way we have been successful in locking in acceptable and really nowadays attractive pricing is by taking our time. If we try to get into the market and layer in 50 to 100 million a day over a single week or couple days then we see that we can impact pricing. But the way we typically done is we’ll layer in anywhere from 10 million, 20 million and 30 million a day. We’ll do it over to two, three, four, five months and we have zero impact on the market. And we've been able to just rollup attractive pricing. So it just going to be over the next six months plus it’s just going to be just an activity that were aggressively paying attention to or actively paying attention to and honestly I really don't think we'll have any issues and sort of locking in prices to update our production which have gone forward.

Okay great. One final clean up question for me. 528 in your deck which is term sales I just wanted to clearly the NYMEX portion you listed it looks like that includes the SP unit now versus your entire quarter debt at this I just wanted to confirm exactly I am seeing that correctly?

Yes.

Okay, great. Thanks lot guys I appreciate the time.

Your next question comes from the line of Becca Followill of U.S. Capital Advisors. Please go ahead.

Good morning guys. You made a comment about having the ability to generate free cash flow long-term, what do you define as long-term in that by 2019, I know within cash flow this year?

It will be over three to five year period back there we’d generating free cash flow.

Any magnitude.

At this point we haven't initiated guidance but has the potential to be meaningful.

Okay, that's what we get. So I wanted to double check with that, second on the long-term gathering CapEx, its around the $55 million for this year is that a good number or would you may be transition to Utica program is it lower than that?

Our gathering spend will be - we’ve got some compression to build in track 100 in Lycoming that will be done next year. We’ve got some gathering to build that 007 though because the Tennessee 300 line goes right through the Procter the spending there would be pretty minimal. And then at CRV if we transition to a Utica program, we’d have next to no capital investment there because we would be using the exact same lines, the exact same compressors.

So, the 55 million maybe going into '18 but after that dropping off?

Yes, that’s right I guess I didn't completely answer your question right, so maybe staying at about the same level that we are now and then trending downward.

Okay. Thank you. And then lastly back to the rate case that you worked, was there any rationale given for the ultralow ROE and the low equity layer?

Well the New York commission is reliant on a ROE model that they are inflexible on. It spits out a number and they adhere to that, that's on the ROE side. And then on the capital structure side, they’re pretty firm on using the parent capital structure and when you look at where we've been with our ceiling test impairments that's made a difference on our equity component.

Got you. Okay, thank you. That’s all I had.

Your next question comes from the line of Timm Schneider from Evercore. Please go ahead.

Hi guys, just one follow up from me. Is there any interest on your side to maybe sign-up on any other pipelines going out of the baseline of your capacity on Nexus of Rover anything like that or if that if under exploration necessarily?

I mean geographically those are quite bit removed from our area of production Timm, so it will in the first instance it would be tough getting over there. But yes, for a long-term as I talked about before with Chris, if we're looking at continued pipeline investments we’ll have to avoid New York. They are either going to be going West sales or East. So into that space what would be really interesting is finding a way to get there right away right now because we think there is going to be some on used capacity at the outset that could probably be gain pretty cheaply but right now there's just no physical way to get it there. And over the long term given the amount of construction that's involved and it have to be a bigger or kind of different project then just getting Seneca's production over to those markets. So our engineers have been busy looking at various options but we don't have anything solidified enough to have a meaningful talk about it.

Okay. Thank you.

There are no further questions at this time. I will turn the call back over to the presenters.