National Fuel Gas Co (NFG) 2018 Q3 法說會逐字稿

Good morning. My name is Chantelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q3 2018 National Fuel Gas Company Earnings Conference Call. (Operator Instructions)

Ken Webster, Director Investor Relations, you may begin your conference.

Thank you, Chantelle, 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.

At the end of the prepared remarks, we will open the discussion to questions.

The third quarter fiscal 2018 earnings release and August 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 participating in the Barclays Energy Conference in September. If you plan on attending, please contact me or the conference planners to schedule a meeting with the management team.

With that, I'll turn it over to Ron Tanski.

Thanks, Ken. Good morning, everyone. Thanks for joining us today. We had another excellent quarter for earnings and things are setting up nicely for both the remainder of this fiscal year and for our 2019 fiscal year. Across all of our reporting segments, operations are going well, as we continue to focus on the basics in each of our business units. The steady nature of our businesses also gives us confidence in our earnings forecast for the next fiscal year. As always, we're looking at ways to tweak certain of our operations to make our already safe system even safer and to grow the businesses where it makes sense.

With respect to our growth projects and our interstate pipeline business, we're in the detailed design phase of our Empire North 205,000 dekatherm per day expansion project, and we're still planning for fiscal 2020 in-service day.

Last quarter, we announced our FM100 upgrade project, where we are working on a companion basis with the Transco project that is also under development. The combined projects will provide up to 330,000 dekatherm per day of additional transport capacity for Seneca for our WDA production. National Fuel is now fully engaged in the prefiling process with the FERC for our FM100 project. As I mentioned last quarter, this pipeline is targeted for completion in late 2021. In addition to these larger projects, we have a number of smaller projects along our line and corridor that are in various stages of development or early construction planning.

Demand for capacity to move gas out of the Appalachian production area remains strong and on our own system, we see most available interruptible capacity regularly picked up by various shippers. The filling up of that capacity helped drive our stronger revenues in the pipeline segment this quarter.

At the national level, there's been a lot of regulatory and legislative activity in Washington, D.C. lately. FERC has received comments from almost 3,000 parties respecting its notice of inquiry into its 1999 statement of policy regarding certification of pipeline construction projects. Since there is no schedule currently set for this proceeding, we don't expect that this notice of inquiry will have any effect on our existing pipeline applications. Even if FERC does not change the statement of policy or any new interstate pipeline projects moving forward, most companies, including National Fuel, will likely add in an extra year in the timing of all of our project schedules.

All the infrastructure construction delays over the past 2 years have not gone unnoticed on Capitol Hill either. Earlier this week, a bill was introduced in the Senate to amend the Clean Water Act to prevent states from blocking federally approved projects. We'll be watching to see how that bill progresses, and we plan to work with our trade associations to seek some certainty in the permitting process. For our Northern access project that is currently blocked by New York, we have not heard any word in either the FERC or the Second Circuit proceedings during this last quarter. As soon as we get any information, we'll let you know how any decisions may affect our plans.

As we pointed out in our earnings release, our Empire Pipeline filed a rate case with the FERC in June. We expect the new rates to go into effect on January 1, 2019, subject to refund. The new rates should help us recover a portion of the revenues that were associated with the anchor contract for our Empire Connector that reached the end of its term and had provided for the transportation of gas from Canada, south to the Millennium project pipeline.

In our exploration and production business, we expect that Seneca will be placing a couple of new well pads online in late August or early September, and we will be utilizing the full 190,000 dekatherm per day of capacity into Transco's Atlantic Sunrise project. That will allow us to finish the fiscal year on a strong note and will help drive our projected 24% increase in production for our next fiscal year.

One of the things we like to see is stronger national gas pricing in Appalachia. Given the strong production across the basin, however, we don't expect to see a big jump in prices anytime soon. We've continued to follow our practice of either locking in firm sales or hedging the price at which we sell our production. As you can see in the back pages of last night's release, we'll be entering next fiscal year with a strong hedge book. We do expect to see an uptick in spot prices after the Atlantic Sunrise capacity comes online as more gas production gets moved out of the producing area. So with respect to our spot sales, we could see some upside in our forecast.

Dave will get into more of our forecast drivers in just a bit, but now I'll let John McGinnis get into the details of Seneca's drilling program.

Thanks, Ron, and good morning, everyone. Seneca produced 44.6 net Bcfe during the third quarter, an increase of 1.9 Bcfe, or 4%, versus the prior year's third quarter. In Pennsylvania, we produced 40.5 Bcf for the quarter, an increase of 2.6 Bcf, or 7%, versus the prior year.

Quarter-over-quarter, our production was down slightly by 0.9 Bcf. This is driven primarily by timing in that we brought on only a single pad towards the end of the quarter. We did have a modest amount of curtailments during the quarter due to low prices associated with maintenance on the Transco system, where prices have since recovered. We now have 11 Utica wells producing in the WDA, 10 in the CRV area, as well as our most recent appraisal well in Boone Mountain, approximately 30 miles south of CRV. Our 2 most recent CRV wells are producing at or above our Utica type curve, and Boone Mountain continues to perform in line with our best WDA Utica well located in Rich Valley. This well has now been online for over 90 days, and on a normalized basis, production has been essentially identical to Rich Valley. So based on the performance to date, we are now increasing our forecasted EUR per 1,000 foot for Boone Mountain at 2.3 Bcf.

Our single EDA rig is now located on our Tioga 007 tract for the first time since 2014. We're currently drilling our second of 6 Utica wells on the same pad as our producing well. We expect drilling to be completed during the first quarter of fiscal '19, with first production schedule to come online late second quarter or early third quarter.

In California, we produced 600,000 barrels of oil during the third quarter, a decrease of 68,000 barrels from our third quarter last year and down 62,000 barrels quarter-over-quarter. This production decrease was almost entirely driven by the sale of the Sespe field in Ventura County.

On a side note, we have recently completed 6-liner poles and drilled 5 new wells on 17N, our farm-in property located in North Midway Sunset. We have seen a nice production response as a result of this activity, growing production by 150 barrels per day. Therefore, we have decided to accelerate some of our 17N fiscal '19 capital into this fiscal year by drilling 11 additional wells in the fourth quarter. While not a significant capital expenditure, our recently accelerated 17N activity is highly economic with returns exceeding 65% at current oil prices. Future investments on this property are expected to see strong returns as outlined in our investor presentation. We now expect to spend around $30 million in California in fiscal '18.

In the East, our fourth quarter production will largely be driven by the timing of the Atlantic Sunrise. Last quarter, based on an assumed mid-August online date, we adjusted our operations schedule, pushing back the online date of 2 Gamble pads on Lycoming County by 1 month. This reduced our forecasted production by a few Bcf. We are now assuming an online date of early September, and therefore, we have lowered our annual production guidance slightly for fiscal '18. With Atlantic Sunrise in service and these pads online, however, our net production should increase around $80 million to $100 million a day, providing a solid start in the fiscal '19. Capital expenditures should range between $350 million and $370 million for fiscal '18, and on the expense side, we're reducing our fiscal '18 LOE guidance by $0.05 to now range between $0.90 and $0.95. G&A between $0.30 and $0.35, and DD&A around $0.70, all on a per unit basis.

Moving to our fiscal '19 guidance, we are forecasting capital expenditures to range between $460 million to $500 million. In Pennsylvania, we will spend between $445 million and $470 million. The key drivers for this increase, include utilizing a 3-rig program for the full year, drilling and completing 100% working interest wells for the entire year, now that the IOG joint development agreement is complete, increasing our completion pace and increased activity of the spot completion crew periodically throughout the year, completing pads in Tioga and Lycoming. One rig will continue to focus in the EDA and the other 2 rigs will be active in the WDA, filling both Utica and Marcellus wells. Overall, we forecast that we will drill 20 Marcellus wells and 22 Utica wells next year in the WDA.

As we continue to transition to our Utica development program, we also plan to drill Marcellus wells on pads that have remaining locations. These Marcellus wells are quite economic in the current price environment and will enjoy the same uplift related to the existing infrastructure as our Utica program. Net production is expected to range between 210 to 230 Bcfe, a forecasted increase of almost 24% year-over-year. In Pennsylvania, we expect to produce between 193 to 213 Bcf, an increase of over 25% at the midpoint. We have locked in 100 -- approximately 140 Bcf of firm sales in Pennsylvania at an average realized price of $2.44 and another 36 Bcf of production with basis protection through our firm sales portfolio. Therefore, we already have around 176 Bcf or 85% of next year's production protected by firm sales, ensuring significant growth at attractive prices. We currently estimate between 25 to 30 Bcf available for sale into the spot market, but as we see opportunities, we'll continue to layer in additional firm sales in an effort to lock in more of this production and avoid price-related curtailments.

So on a final note, we envision remaining at a 3-rig full-time WDA frac crew and spot EDA frac crew over the next few years. At this activity level, we can fulfill our firm sales portfolio and grow into our new firm transportation commitments, including the $300 million a day commitment with Transco towards the end of 2021. As stated last quarter, over the next few years, we expect to grow natural gas production on average between 15% to 20% per year.

And with that, I'll turn it over to Dave.

Thanks, John. Good morning, everyone. The third quarter of fiscal '18 was an excellent quarter for National Fuel with per share earnings up 6% compared to the prior year. Last night's release does a good job detailing the drivers relative to last year, so I won't repeat them here.

Our $0.73 per share of earnings was a bit higher than street estimates for the quarter, and there were 3 main items that contributed to that out-performance. First, Seneca's $0.84 per Mcfe of LOE for the quarter was below the low end of the range of our $0.90 to $1 guidance range. A number of individually small items, all of which were in our favor, contributed to this decrease, including lower steam fuel in California and lower utilities and labor expenses in both divisions. We have a few maintenance projects planned that will cause Seneca's fourth quarter per unit LEO to be in the low $0.90 area, but feel comfortable lowering our fiscal '18 LOE guidance to a range of $0.90 to $0.95 per Mcfe. Looking to fiscal '19, as low-cost East division natural gas production ramps, we expect LOE will continue to decline and forecast a range of $0.85 to $0.90 per Mcfe.

Second, at our regulated subsidiaries, O&M expense was several million dollars lower than we had forecast for the quarter. Much of this is related to the timing of spending between the last 2 quarters of the fiscal year. For example, because winter weather extended well into April, utility restoration work that typically starts in that month was pushed to later in the year. Also, at the pipeline companies, certain maintenance projects that had been originally forecast for the third quarter will now take place in the fourth quarter. Even considering these timing issues, our team has done a great job controlling costs. As a result, we now expect full year O&M expense at the regulated companies should be pretty much flat compared to fiscal '17.

Third, our effective income tax rate was reduced by about 150 basis points as a result of some adjustments we recorded when we filed our tax return. Looking to the remainder of this year and into next year, we expect our effective rate will be in the 25% area. In terms of cash taxes, we expect to be in a net refund position in fiscal 2019. You recall that under the new tax law, AMT credits carryforwards are now refundable. We expect to recoup approximately $45 million of those credits in fiscal '19.

Shifting to guidance. Based on the strong results in the third quarter, we're raising and tightening our fiscal '18 earnings guidance to a range of $3.30-$3.40 per share. The details supporting this range are included in last night's press release.

Looking to fiscal '19, we're initiating preliminary earnings guidance in the range of $3.30 to $3.60 per share, at the midpoint a $0.10 increase over fiscal '18. As John mentioned earlier, Seneca's production forecast for next year is 210-230 Bcfe. As a reminder, this range does not include any forecasted price-related curtailments. At the midpoint of this range, our spot volume exposure is 25 to 30 Bcfe or just over 10% of our forecasted production. We're quite pleased to have such limited spot pricing exposure as we approach fiscal '19, and we'll likely add firm sales as our operations schedule and well turn-on dates firm up.

For pricing, we're assuming a Henry Hub gas price of $2.75 per MMBtu and a WTI crude oil price of $65 a barrel. We're also assuming that spot prices in Appalachia will average $2.40 in the winter heating season and $2 in the summer and shoulder months. While these prices are somewhat lower than what we've achieved in the spot market in recent months, they are in line with what we're seeing in the forward markets. We are well hedged going into the year and as a result, changes in spot prices will have a relatively small effect. For reference, a $0.10 change in natural gas will impact earnings by about $0.06 per share, and a $5 change in oil has about $0.03 per share impact.

From an operating expense standpoint, as I mentioned earlier, we're expecting Seneca's LOE to be in the range of $0.85 to $0.90 per Mcfe. G&A will grow modestly in absolute dollars, but with our forecasted production increase on a per unit basis, this should decline to the $0.25 to $0.35 per Mcfe area.

It's worth noting that our production growth is more back-weighted in fiscal '19, so as you think about both LOE and G&A, we expect per unit cost to be higher on the first half of the year and lower in the back half.

Our DD&A should continue to approximate our long-term F&D costs. Our guidance assumes a range of $0.70 to $0.75 per Mcfe. The Gathering segment's throughput and revenues will track Seneca's East division production. As a result, the nearly 25% increase in Seneca's net production should translate into a similar percentage increase in Gathering revenues, to a range of $130 million to $140 million. Given the current year's investment to support Seneca's activity, we expect both operating and depreciation expenses will increase relative to their current levels, but a large portion of the Gathering segment's revenue increase should go right to the bottom line.

Shifting to the regulated segments, our fiscal 2019 will be a down year for the Pipeline & Storage business. As I discussed on our previous call, our Empire Pipeline expects that the anchor shipper on the north to south path of Connector line will not renew its contract when it expires this coming December, which will impact revenues by about $14 million in fiscal '19.

In response, Empire filed a rate case in late June, seeking an $11 million rate increase. In the filing, Empire also addressed the FERC's new income tax rule making. New transportation rates will go into effect on January 1, 2019, subject to refund. The settlement charge will be assigned shortly, and we hope to resolve this proceeding in the coming quarters. The issues in the case are pretty straightforward, and we have a good history of settling our pipeline rate cases. Our guidance incorporates a modest amount of revenue from this case commencing in our fiscal second quarter, which we'll update as the regulatory proceeding plays out.

We expect a significant increase in compressor maintenance and pipeline integrity expenses in fiscal '19. Major overhauls are required on our compression engines when they reach certain operating hour thresholds. Several of our units will reach these thresholds in 2019, including a turbine unit, whose cost to overhaul is $1.8 million. All told, compressor maintenance expense is expected to increase by about $3.5 million over 2018 levels.

On top of that, as you know, PHMSA rules require us to assess the integrity of our major pipelines on a 7-year cycle. Fiscal '19 happens to be the highest cost year in the 7-year cycle, about $1 million higher than 2018. In total, as a result of the overhaul and integrity work, as well as some general cost inflation expected in our other expense categories, we expect fiscal '19 Pipeline & Storage O&M will be up about 5% to 10% over this year. Things should improve for the Pipeline & Storage business in 2020. O&M expense should be more moderate. The rate -- Empire rate case should be resolved, and we will place in service our Empire North and Line N to Monaca expansions, which combined will add almost $30 million of annual revenue. At the Utility, our guidance reflects normal weather. Given that weather in fiscal '18 was largely normal, this assumption really doesn't have any impact on our year-over-year earnings forecast. However, we do expect to see a modest increase in our underlying margin, driven by the implementation of a system modernization tracker in New York, which should kick in sometime in the first half of the fiscal year once we surpass a plant balance target that we set in our last rate proceeding. Revenues from the tracker should largely offset our forecasted expense increases, which are largely attributable to higher personnel-related costs, including labor and associated benefits.

Looking to capital, the full breakdown is contained in last night's release. At the midpoint, our fiscal '18 forecast is about $30 million lower than our previous guidance due to the timing of spending between fiscal years. For fiscal '19, our initial guidance is for spending between $745 million and $845 million. Principal driver of this increase is spending in the E&P business, which John hit on earlier. In our Pipeline & Storage businesses, spending will be up about $50 million, largely driven by spending on the Empire North and Line N to Monaca projects I mentioned earlier. In addition, our modernization program will add another $60 million to $80 million of spending during the year. We expect spending across the other segments will be largely consistent with 2018.

Lastly, from a financing perspective, we expect our funds from operations should cover substantially all of our capital expenditures in fiscal '19. Adding our dividend to the equation, we expect the financing need in 2019 in the $150 million area. Given our forecasted year-end cash position, we expect to finance this with cash on hand, though it's possible changes in working capital could push us into a modest borrowing position at various points in the year.

With that, I'll close and turn it over to the operator to open the line for questions.

(Operator Instructions) Your first question comes from Holly Stewart with Scotia Howard Weil.

Maybe just to start off with just a little bit in the weeds. Question for John on the CapEx split between the Marcellus and the Utica in 2019, if you've got it. I know you gave us a pretty good detail on well count splits.

Yes, I don't have it broke down by capital expenditures. I can certainly get it. I can walk through how many wells we'll drill, both Utica and Marcellus, and completion in each of these areas, but I don't have it broken down by capital expenditures.

That detail will be great.

Okay. Let's start in the WDA. For fiscal '19, we'll be drilling 20 Marcellus wells and 22 Utica wells and completing 10 Marcellus wells and 14 Utica wells. So essentially, drilling 42 Wells, completing 24. And then in the EDA, our plan currently is to drill 24 wells, completing 21. Most of those will be Marcellus and Lycoming area. We'll complete 6 Utica wells in 007 in fiscal '19 and then the rest are all Marcellus wells.

That's great. And then, John, I didn't catch. Were there any production shut-ins during the quarter?

There were. We had made a little under 0.5 Bcf of curtailment. There are some maintenance on the Transco system. And so in May was the key -- was the main month, but we did have some curtailments over the quarter.

Okay. And do you happen to have that year-to-date number at your fingertip?

I do not. Ken can get that to you.

Okay. Great. And then just maybe one more. And you might not want to kind of get this granular into kind of Rich Valley, Boone Mountain well counts. But just thinking about how far south Boone Mountain is. Is there any gather -- is your system -- Gathering system extend that far? Would there be any kind of additional needs there from the infrastructure side, if you invest more dollars down there?

Yes, yes, definitely. One of the reasons we drilled at Boone is because we could produce it immediately into the -- what we have some infrastructure there, but it's very much capacity constrained. As we grow out of Rich Valley south towards Boone Mountain, yes, the infrastructure will have to be built.

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

If I could start and keeping on Seneca for a moment. Just curious, I appreciate the update on the EUR expectations in Boone Mountain. Wondering if there were other learnings that you garnered from the appraisal program, either new production or just having a longer period of existing production from the pool of appraisal wells besides the -- obviously, the EUR matters, but just wondered if there's anything else that you're learning as you go through that process.

Yes, nothing since the last quarter, Chris. We still -- we are planning on drilling another appraisal well in fiscal '19. But whether that's going to be located in Boone Mountain to test a different formation or deeper formation or in a different location has yet to be decided.

Okay. And in terms of the production profile, John, for next year. I'm assuming with Atlantic Sunrise coming on in September, will always have step up here in fiscal 4Q and imaging 1Q will be quite strong in terms of the year-on-year growth and quarter-on-quarter growth. But I'm just wondering how the rest of the year looks in terms of your expectation at this point. Anything you could help us from a modeling would be helpful.

Yes, definitely Lycoming will be, at least in the first quarter, will be our largest growth area. We don't have additional pads coming on until towards the end of the first quarter until, yes, end of the first quarter in the WDA. So that will be towards the back half of the first, early second quarter, we'll see some growth in the WDA. But again, that will be pretty late.

Okay. So ramp early and then sustained through the balance of the year is a decent view of the profile. Is that right? (inaudible)

Yes, our first 6 months will be fairly flat, except for the -- obviously, the initial bump in -- very early in Lycoming and then towards the mid and back half is when you start to really see significant growth.

Okay. And Dave had mentioned some of the things which I think help explain the reduction in your per unit operating cost at Seneca. It sounds like, at least for fiscal '19, some of that has to do with the move towards EDA production at a lower cost with Atlantic Sunrise, but I'm curious if there are other noteworthy items. Certainly, third quarter cost reductions were key, at least relative to how we had things modeled. So just curious any help on that front in terms of other items that are affecting Seneca's cost improvement.

Sure. Actually, it was split pretty evenly, at least year-over-year between California and Pennsylvania. The drivers out in California were the sale of Sespe, was a big piece of it. That was a fairly high LOE field. We had lower steam fuel costs year-over-year and much more limited well workovers than we were last year. If you remember last year, about third quarter going into fourth quarter, we begin to ramp up that -- the workover activity out there, as oil prices began to ramp up. So that was a big driver. And then in the east, we did see lower compression cost in Tioga and really what drove that was we transferred those compression facilities to our midstream company, and then we also saw lower road maintenance, which was fairly high, and saltwater disposal costs. When we took over as operator from the EOG assets, we were able to get in and we focused quite a bit of attention on trying to reduce the saltwater or the disposal costs there and so that also made a difference.

Okay. And so a lot of those things, obviously, carried forward into '19 as well?

Yes. Yes.

I guess, on the costing front, we're going to stay there for a moment. Obviously, we're seeing a pretty tight labor market nationwide. You guys are forecasting, not only at Seneca but the other businesses as well, an acceleration activity as we move into next year. I'm just curious how you guys feel in general about staffing levels, ability to procure talent and the cost of it?

Actually, I feel pretty comfortable. We've been -- at least on the Seneca side, we've been -- during the downturn, we run a fairly lean ship, and so there wasn't a lot of change even during that period. And we've been able to add individuals as we've been -- as we ramped up our activity. So we just haven't seen that issue.

And Chris on the pipeline side, we have added some engineers lately, I mean -- but really, that's been pretty steady all the way through with respect to the construction planning and design of those systems. The pick -- the real pickup will obviously be in the contractors, when we have third-party contractors that are out doing the construction. So that shouldn't impact our overall headcount going forward that much.

Okay. Just the actual field crews will come with the contracting staffs and so they're ex-NFG, but they're driving your projects. Okay, I understand.

Right.

I guess, switching gears, if I could, just 2 questions, Dave, related to tax. Obviously, the effective earnings tax rate declined. I think you did a brief review of some of the details of that in the prepared remarks. I'm just curious, I don't think I heard it all, so if you don't mind, just indulge me a quick review of that. And then you've noted 25% as for the guided range for '19. I'm curious, if that's also been ranged to assume in the years beyond it knowing what you know now.

Well, starting with your last question, yes, based on what we know now, 25% of the -- what we'd expect long term, I didn't really have a whole lot more to say on taxes beyond the 25% rate that we expect for '19 and for '18. I guess, the other thing I mentioned was the AMT credits that are refundable that we expect to recoup about $45 million of those in '19.

So I guess, that's my other question, on the tax side -- cash tax side. You had talked about being in the net refund position. You mentioned those $45 million of ATM (sic) [AMT] credit. Is that -- I guess, what is the -- I don't know if you're willing to share, but what is, as you have it modeled now, the total net refund you're expecting? Is it the $45 million? Or is that the credit and it's something less than that?

So you're saying, just for '19 or all of the AMTs credits over time?

No, just -- as I'm trying to get my cash flow statement to model close to yours, I'm curious, how much of a net refund from a cash per -- cash tax perspective you're assuming.

Yes, about $50 million in total.

Your next question comes from Becca Followill with U.S. Capital Advisors.

I know it's hard to say since the FERC doesn't show their hands, but any thoughts on what's taking the FERC so long on Northern Access? They've already ruled on Constitution. I think, you've put in a request for them -- once again for them to look at it. Any thoughts on that? And whether or not going from 5 commissioners to 4 is going to have an impact?

Good questions, Becca. No, we -- the only thing we can say is, obviously, and we have always pointed this out, that the facts in our case are different from those that Constitution had. So FERC needs to take a different look in our situation. So I -- that's what's driving it. Obviously, there is philosophically, now with Powelson leaving, there'll be kind of a split philosophically between 2 and 2. But that philosophical split really shouldn't affect the issues that were in our case. So I mean with respect to our particular in Northern Access, no, we don't think that will impact us.

And then also preliminary, but on a National Fuel Gas supply with the latest decision from the FERC, any thoughts on what you guys plan to do? What options you would like to take once you file your 501-G?

Yes, we're still evaluating that, Becca. We have until December to make that filing, and we'll do so. From a practical standpoint, Supply Corporation has a rate case that it has to file by the end of next year. I think it's likely it will all -- everything will get all rolled into 1 proceeding, if you will.

And then last one, some of the other companies on the E&P side have talked about some downward pressure on service costs. Have you seen any of that?

We have not, yet.

(Operator Instructions) Your next question comes from George Wang with Citigroup.

Just a couple of questions. Firstly, do you guys have any thoughts on kind of strategic initiatives, just a tool to unlock value for various different segments, whether it's E&P, kind of Utility, kind of Gathering?

George, I guess, the -- we kind of layout basically our thoughts on that in the first few pages of the investor deck and that we filed also last night. And as we look at it going forward, given the efficiencies that we see between all the operating segments, our first focus is -- or near-term focus is developing the fee acreage that Seneca has and building out the Gathering systems in order to get Seneca's production to market. So both of those, the timing and the working on those projects together help us really plan our CapEx. So we don't have wells waiting on pipeline or we don't have pipe sitting waiting to be filled. So I guess, first and foremost, that's our focus here for the near term.

Right. Got you. And also on the E&P side, just, you guys mentioned kind of spending within cash flow. So -- and also you guys guided kind of funding CapEx, internally drain your cash flow. So, I mean, is this going to be the guideline or limitation for the kind of future growth going forward? Just especially in terms of further developing the Utica acreage. I mean, do you think kind of spending in line with cash flow is going to kind of be reality going forward?

Yes, I think that's our plan for over the next few years, given where pricing is, to, I'd say, generally live within cash flows. I think a 20% growth rate is pretty good while living within cash flows.

There are no further questions at this time. I will now turn the call back over to Ken for closing remarks.

Thank you, Chantelle. 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, August 10. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1 (800) 585-8367 and enter a conference ID #1984229. This concludes our conference call for today. Thank you, and goodbye.

This concludes today's conference call. You may now disconnect.