National Fuel Gas Co (NFG) 2017 Q2 法說會逐字稿

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)

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's Financial Forum later this month in Orlando. 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.

As you saw on our earnings release last evening, we had another strong quarter, both financially and operationally. In our Upstream Exploration & 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 have helped drive earnings higher in our Exploration & Production segment and our Gathering segment.

John 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 an anchor shipper for the baseload capacity on our Empire North project and look to get some additional proceeding agreements in place for the remaining capacity over the next quarter.

In our Utility business, recent audits 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 had 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 agency 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're 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 on a 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 started 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 on areas where we can grow while our lawyers are busy with the DEC in the Second Circuit.

With respect to our loss -- with respect to that lawsuit, unless we're able to negotiate a resolution, we expect our litigation will take a minimum of one full year to resolve, but likely longer. Assuming a timely resolution and the need to remobilize all of the engineering and contractor logistics surrounding the Northern Access project, you'd be looking at an in-service date 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's greater clarity around Northern Access, Seneca will continue to operate a 2-rig program in Appalachia, with one rig dedicated to the Clermont/Rich Valley area and another splitting time between Tioga and Lycoming Counties. A single frac crew will handle completions. At this level of activity, Seneca should be able to grow production by at least a 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 Clermont/Rich Valley and converting the delivery point of previously executed Dawn-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 at realized fixed prices that exceed the netback price we would have achieved via deliveries to Dawn.

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 flows under its 2-rig program. Longer term, as we grow our production base, 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 can effectively reuse existing infrastructure. Given the expected growth in Seneca's production, the Gathering business should generate significant free cash flow over the next 3 to 5 years.

In the Pipeline & Storage business, we expect that the recent New York DEC permit interpretations will not interfere with our normal maintenance and system modernization activities. Our annual capital requirements should be in the neighborhood of $100 million. Expansion projects like Empire North always cause 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 to our dividend and further improve our balance sheet.

Most 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 remained 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's 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 planned 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 they will begin drilling in Lycoming as we prepare for our Atlantic Sunrise capacity mid-2018. The rig will then move to our DCNR 007 Tract in Tioga County to begin a Utica development program. Our first Utica appraisal well in Tioga continues to outperform expectations and this well has now produced over 2 Bcf in less than 6 months. Based on the strength of this well, we believe we have around 1 Tcf of potential resource within the Utica on this tract. We 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 2 WDA Utica wells had now been online for over 4 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 3 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 million and $250 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 6 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 few years in each of our key areas.

We expect further basis improvement as Rover and other pipeline projects in the basin add 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 2-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 BOEs, a 6% decline from last year's 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 work overactivity 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 and return to production trends similar 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 2,100 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 4x that rate.

Immediately adjacent to South Midway, we have just returned 11 wells to production and have drilled 4 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. And 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 nonregulated 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 business' $0.03 per share increase in earnings. Spot prices in Appalachia were strong, averaging approximately $2.60 per MMBtu, not more than $1.40 over last year. Lastly, Seneca saw 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 & 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 this segment to total between $295 million and $300 million for the full fiscal year.

Lastly, earnings at National Fuel Resources, our 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 its 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 purchase gas costs squeezed its gross margin for the quarter.

Looking at the rest of the year, we're increasing and tightening full year earnings and 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 for pricing-related curtailments. The low end assumes we curtail 100% of our spot production for the last 5 months of the year while the high end assumes we have no curtailments. This makes our production guidance fairly conservative. Should we continue to produce without curtailments, 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 has traded off a fair amount, but we're well-hedged. For the remainder of the fiscal year and assuming the midpoint of our production guidance, we're 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 reference, a $5 change in oil equates to about $3 million in EBITDA or $0.02 per share.

Given the strong pricing in Appalachia, we're upping 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're being conservative. Recent pricing in the basin has averaged 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 $1, somewhat higher than the $0.91 per Mcfe rate for the first 6 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 & Storage segment where the delay in Northern Access caused us to remove about $0.03 per share of [AFEDC] 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 of rate base and 8.7% ROE and 43% capital structure, the rate of work equates to about a $0.05 per share impact on earnings.

Our updated consolidated capital spending for fiscal '17 is a range of $450 million to $530 million, at the midpoint down $100 million from our previous range. Substantially, all of the change is related to the delay in the Northern Access Project, which reduced planned Pipeline & Storage spending by $115 million. Combined E&P and Gathering CapEx is higher by 100 -- by $15 million due to changes in the timing of spending between fiscal years. There is no change to 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'd 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 refinance 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 from Scotia Howard Weil.

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 the 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 a 42-inch pipeline using the same construction methods that were deemed unacceptable for our project, it just indicates how arbitrary the decision-making can be. So I -- 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.

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

Yes. I mean, that -- we've talked about other routes before or, if you will, a 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 interconnections there. But as we've stated before, you get into this situation of pancaking additional rates and that will affect the ultimate economics of our drilling in the WDA.

Sure. Okay. Great. And then, maybe one for John, just on the new 10% 3-year CAGR that you put 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 forecasts based on the 2-rig case. We'll be 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 we're moving 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 grow significantly above 10% next year.

Having said that, moving into 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 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.

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

So looking at Slide 26 in the presentation, it really looks like you've done a great job in layering in the firm sales contracts thus far. So, I guess, just wondering if you could give just a little more color on what the landscape looks for layering in even more contracts going forward?

Yes, absolutely. We're -- 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 for our 007 development program. We are actively layering in fixed sales, firm sales at CR -- at Clermont/Rift Valley, but -- and 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-plus 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 then, for a quick follow-up, I was just wondering if there was anything specific that you could point to regarding that EUR uplift with the Utica wells that you mentioned?

Yes, absolutely. It's just the decline has been a lot less than we anticipated. We're comparing these wells to some of the decline curves that we see through Potter into Tioga and the 2 wells that we have online. Now, it's only been 4 months. So we still have a ways to go, but the decline has just been a lot less than we've seen in other areas. That's what's driving the increase.

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

I was wondering if you guys had any recourse regarding Northern Access with FERC to perhaps supersede the state?

Yes, Tim. I mean, if you read the back and forth that we are already had with -- well, not back and forth with FERC, but our filings with FERC and then response by the New York DEC with respect to that, yes. I mean, we think there's a possible avenue for preemption from -- by the FERC 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 or maybe late summer, for them to able to do that. But yes, there is -- I mean, I think our arguments were quite clear in the paperwork that we filed with FERC which is on rehearing. 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 maybe refile or just sort of stay away?

Well, I mean, obviously the cost pressures or 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 were also looking at a possible appeal of that decision with respect to there, again, 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. And then, as a result, that's why we've been able to achieve the lowest rates, as I mentioned before, than 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.

Your next question comes from the line of Chris Sighinolfi from Jefferies.

Ron, I wanted to maybe at least pick up where Tim left off just on the regulatory climate. I mean, clearly, I've not been following it quite as long as you have. And it certainly seems like we've taken a couple of steps back in the last couple of years, culminating with the things that you talked about, the 401 permit announcement, 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 an over-political agenda which has produced those, I guess.

But leaving politics aside and just think about it from a business perspective, I guess, I have a couple of questions. First, it seems like you agree with that assessment given the commentary you offered in the prepared remarks, but I'm 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, some of 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's any potential divestiture opportunities of your New York businesses?

Well, there's a number of questions in there, Chris. So let me try to tackle it. If you look at any historical period -- and let's look back over, say, 5 to 9 years. In over 9 years, we have invested over $6.2 billion in all of our businesses. Through those years, 14% to 16% of that was invested in New York. And over the same time frame, 74% to 77% was invested in Pennsylvania.

With our Northern Access Project, we were looking at a substantial increase of investment in New York State. And let's be clear, we'd still love to achieve some sort of negotiated solution for that project. But when the governor won't take 10 minutes to respond to repeated requests of the CEO of a New York-headquartered company with 1,200 employees in the state and the Commissioner of the DEC won't return my calls, I mean, who are we going to negotiate with? And so since it appears that our growth investments are not necessarily welcome, our 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 that likely avoid New York. Now, you might find it counterintuitive that we would consider investing more in California where 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 are 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 answered your question, but that's kind of generally where we see things going.

No. I mean, it's helpful. I mean, 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 what the commission structure there was like and the unpredictability of outcomes led to their decision to invest heavily in other regions. So I was assuming the answer was going to be similar for you, but just helpful to hear from you directly on it.

I guess, switching gears a little bit and then extrapolating from that, you -- I think you had mentioned or Dave had mentioned sort of a $500 million to $600 million a year 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 the 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, I don't know if M&A would feature in that, if there is something we could discuss that might be on your wish list? And then, it has been a very long kind of time to discuss, but your buyback program, I think you still have like 7 million shares authorized to be repurchased. At what point does that maybe come back into something we should consider?

Yes. I think with respect to the buyback, yes, we're -- we've obviously always been watching that. That's been out there since, I think, 2007. Obviously, we stopped that during the capital markets issues in 2008, but we do have that available. I guess, we'd prefer -- yes, 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 Exploration & Production side. And we're always looking at things as you can imagine. The -- our history has been all across the natural gas value chain. And we'd love to have more pipeline investments that can serve dual purposes 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, we think, makes sense from a number of point of views, from energy security in the state to helping grow a New York-headquartered company. It just -- it makes a lot of sense. But if we can't, we'll be looking at things likely across Pennsylvania or -- and as always, as we've looked at M&A on the Utility side, it's always been adjoining 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 Utilities side.

Okay. Really appreciate the thoughts on that. I guess, one final question for me, and just switching gears -- and for John. I know there was some earlier questions on it, but I just wanted some help in how we think about the process of converting those Dawn firm sale contracts and basin contracts. You've mentioned the new contracts you've added. And I realize this whole process is similar to what you did a couple of years ago when you voluntarily delayed Northern Access.

But, I guess, 2 questions. One, the dynamics around how you do the conversions? And then, second, how deep is that market? Your comments about needing an evacuation route, a physical evacuation route is what would sort of underpin meaningful, long-dated risks for Seneca? So how do you run a program, depending on how deep firm sale agreements should we get? I mean, can we tie in 2020 right now? Or is the market just not there for it?

Actually, the market is there. A lot of our -- the firm sales that we've been layering in at 007 for our Utica development in Tioga, most of those are 3-year -- 3 to 5-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. Dawn has slipped a little bit. We converted to NYMEX and then layer in a basis differential off of NYMEX at our Clermont/Rich Valley receipt points. 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 2.

The only thing we need to be careful of a little bit is 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 million to $100 million a day over a single week or a couple of days, then we see that we can impact pricing. But the way we've typically done it is to layer in anywhere from $10 million, $20 million, $30 million a day. We'll do it over 2, 3, 4, 5 months. And we have 0 impact on the market and we've been able to just roll up attractive pricing.

So it's just going to be -- over the next 6 months plus, it's just going to be just an activity that we're aggressively paying attention to or actively paying attention to. And honestly, I really don't think we'll have any issues in sort of locking in prices to fit our production curve going forward.

Okay. Great. One final cleanup question for me. Slide 28 in your deck, which is a firm sale slide, I just want to clarify the NYMEX portion you have there. It looks like that includes the SP unit now versus you prior quarter deck. I just wanted to confirm if that was -- I'm seeing that correctly.

Yes.

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

You made a comment about having the ability to generate free cash flow long-term. What do you define as long-term? Is that by 2019? I think you're living within cash flow this year.

It will be over a 3 to 5-year period, Becca, that we'd be generating free cash flow.

Any magnitude?

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

Okay. That's what we get. So I just wanted to double-check with that.

Second, on the long-term Gathering CapEx, is around the $55 million for this year, is that a good number? Or with you maybe transitioning to the Utica program, is it lower than that?

Yes. Our Gathering spend will be -- we've got some compression to build in Tract 100 in Lycoming that will be done next year. We've got some Gathering to build at 007 though. Because the Tennessee 300 line goes right through the Tract, 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'd be using the exact same lines, the exact same compressors.

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

Yes. 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. And then, lastly, back to the rate case in New York, was there any rationale given for the ultra low ROE and the low equity layer?

Well, the New York Commission is reliant on an 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's capital structure. And when you look at where we've been with our ceiling test impairment, that's made a difference on our equity component.

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

Just one follow-up on me. Is there any interest on your side to maybe sign up on any other pipelines going out of the basin? I don't know if you have capacity on NEXUS or Rover or anything like that or if that's (inaudible)?

Geographically, those are quite a bit removed from our area of production, Timm. So it would be -- in the first sense, it will be tough getting over there. And -- but yes, I mean, for long-term, as I talked about before with Chris, if we're looking at continued pipeline investments as you have to avoid New York. They're either going to be going west, south or east, so the -- into that space. What would be really interesting is finding a way to get there right away right now because we think there's going to be some unused capacity at the outset that could probably be gained pretty cheaply. But right now, there's just no physical way to get it there. And then, over the long-term, given the amount of construction that's involved, it would have to be a bigger and a different project than 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.

There are no further questions at this time.

I turn the call back over to the presenters.

Thank you, Virgil. 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 3:00 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, May 12. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, please call 1 (800) 585-8367 and enter the conference ID number, 456885.

This concludes our conference call for today. Thank you and goodbye.