National Fuel Gas Company (NFG) Q3 2017 Earnings Report, Transcript and Summary

Good morning, my name is Liandra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q3 2017 National Fuel Gas Company Earnings Conference Call. [Operator Instructions] Thank you. Mr. Brian Welsch, Director of Investor Relations, you may begin your conference.

Thank you, Liandra, 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 third quarter fiscal 2017 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 next month in New York City. If you plan on attending, please contact me or the conference planners to schedule a meeting with the management team. And with that, I'll turn it over to Ron Tanski.

Thank you, Brian, and good morning, everyone. We're very pleased with our operating performance for the quarter. And as you can see from our earnings guidance, we expect that our fourth quarter results will also be in line with Street expectations. Over this summer so far, field conditions have been excellent for our construction crews undertaking our various upgrade and modernization programs in our pipeline systems in the Utility segment and Pipeline & Storage segment. Would have been a great construction season for our Northern Access Project also. Unfortunately, it's been the lawyers that have been very busy on that project since April. Our appeal of the New York Department of Environmental Conservation's denial is on file in federal court in the Second Circuit, and we have litigation filed in New York State Court regarding the denial of the various state permits. If the timing of our litigation is similar to that of Constitution Pipeline's Second Circuit case, it could be next spring before we get an answer from the court. So as I mentioned in the last call, this project is on hold. And if we have to go the full litigation route, that hold would likely last until 2020. However, with a quorum reestablished at the Federal Energy Regulatory Commission as of yesterday, it's possible that FERC could adopt our arguments and our rehearing request and determine that the DEC waived its opportunity to act on our Water Quality Certification by exceeding the time frame set out in FERC's scheduling order. If that were to happen, we could receive a notice to proceed from FERC much earlier. In the Utility segment, we filed an appeal of the rate order from the New York Public Service Commission. There were a number of issues that we raised, the 2 primary ones being the low authorized rate of return and the low equity component. So while the lawyers are busy, field operations in both the Pipeline & Storage and Utility segments are moving along quite well. And we once again expect that our systems will be in tip-top shape when we enter into this year's heating season. Looking a little further out, we're seeing continued economic development and expansion in Pennsylvania, and that's driving a couple of our projects that are also moving along on schedule. Our $27.5 million Line D Expansion Project designed to move more gas to the Erie, Pennsylvania market area should be coming online this November, which will add $2 million in annual revenues. We're also planning for a mid-2019 in-service date for our lateral to the Shell cracker plant in Western Pennsylvania. That $18 million project would add another $3.25 million in annual revenues. We're also pleased to report that, we have precedent agreements in place for our Empire North expansion project. Given the commitments that we have, this project will be designed as a 205,000 dekatherm per day expansion of our Empire Pipeline. It could be operational around November 2019, or the beginning of 2020 fiscal year. Our initial capital cost estimates are in the $135 million range, and this project would add approximately $25 million in annual revenues. We're in the process of assembling our FERC application, and we'll be making that filing over the next few months. Since this project is all compression with no major pipeline construction, we would expect that the permitting for the project should not run into major roadblocks. At our Exploration and Production operation, Seneca is transitioning from its Marcellus development program to a Utica development program. Our initial Utica results in the Western development area indicate that per well reserves may be significantly higher than our Marcellus wells and drive better economics. John will get into more detail regarding this transition in a little bit. But overall, we expect that our 2-rig Utica program can deliver a 10% to 15% compound annual growth rate in production for at least the next 3 years. This production growth will drive a growth in earnings at both Seneca and our Gathering business over most of the same time period. The only exception to that earnings trajectory is our next fiscal year, where we expect earnings to be down slightly. The earnings decrease is the result of a number of higher-priced hedge contracts rolling off of Seneca's hedge book. Now this is not a surprise, as we have regularly delineated information on all of Seneca's hedges and our earnings releases. Dave will get into more details of next year's earnings drivers later in the call. I'll wrap up by saying that, our core business plan remains intact. We've got great assets, and we're continually working to make them better. Seneca continues to develop economic reserves even at today's commodity prices and has been successful at layering in firm sales to match our expected increased production levels. Our pipeline engineers are always looking at ways to expand throughput on our system, and expect we'll be able to continue adding small incremental projects like the Line D Expansion I mentioned earlier and a host of expansions that we've completed through the years along our line and corridor. While each individual project is not major, let me remind you that, we have invested approximately $500 million in expansion pipeline projects since 2010, that have associated annual incremental revenues of $106 million. Over the same time frame, we've also invested $510 million in Gathering pipelines that have added $110 million in incremental revenues. And that's on top of the $350 million in normal modernization investment in our system over the same period. Our consolidated outlook for this year and next year is to live within cash flows, increase production and keep our utilities customers' annual bill affordable. This past June, we increased our dividend yet again, and we plan to operate the company to be in a position to consider another increase next year. Now John McGinnis will give an update on Seneca's activities.

Thanks, Ron, and good morning, everyone. Seneca produced 42.7 net Bcfe during the third quarter, a decrease of 1.3 Bcfe or 3% versus the prior year's third quarter. In Pennsylvania, we produced 38 Bcf for the quarter, a decrease of 1 Bcf or 2% versus the prior year. This decrease in gas production was due mainly to a lower operating interest on new Marcellus wells related to the IOG joint development agreement in the WDA, a 1-rig program since March of 2016, a natural decline over the last 12 months in the EDA, where the last development pad was brought online over 2 years ago. Our operated gas production during this quarter however, actually increased 5% from the prior year. In May, we added a second rig in Pennsylvania. This rig is currently drilling wells in Lycoming County in preparation for the onset of Atlantic Sunrise. We're currently planning on drilling 17 wells on 3 pads in this area, before moving the rig north to Tioga to begin drilling Utica wells on our DCNR 007 Tract. The first Lycoming pad, which consist of 7 wells, is scheduled to be online by our second quarter fiscal '18 and first production from our 007 Utica wells to occur early in fiscal '19. In California, we produced 668,000 barrels of oil during the third quarter, a decrease of 54,000 barrels from our third quarter last year. This increase -- or decrease was primarily due to changes in our steam operations and a significant reduction in well work overactivity beginning last year as a result of low oil prices. Quarter-over-quarter, our oil production was essentially flat, and we have recently ramped up our work overactivity. As a result, our total LOE increased $1.8 million this quarter or $0.07 per Mcfe on a per unit basis, driven mainly by this increase in work overactivity and partially due to increased steam fuel cost. We'll see higher LOE through the remainder of the year as we continue to bring on idle wells in California. In fiscal '18, we expect to see California per unit LOE moderate, but production flat to slightly growing. In terms of guidance for the remainder of this fiscal year, net production will range between 170 to 180 Bcfe, an increase of 2.5 Bcfe at the midpoint. Even though we have had some curtailments recently as a result of reduced spot prices, this midpoint assumes minimal curtailment and is about 8.5% higher than our total net production last year. Our forecasted increased year-over-year was driven primarily by greater spot sales through most of the year, offset by a lower working interest as a result of the IOG joint development agreement. CapEx should range between $230 million to $250 million, LOE between $0.95 and $1, G&A around $0.35, DD&A around $0.65, all on a per unit basis. Moving to the Utica/Point Pleasant appraisal program, we are now producing from 5 wells in the WDA Clermont/Rich Valley area. Our latest Utica well in this area has now been online for just over 2 months and is our best well to date from this program. In fact, this well is projected to be the largest shale well we have drilled in the WDA. The projected EOR per thousand foot for this well is over 2 Bcf. And as a result, we are now increasing our Utica type curve in this area to range between 1.6 to 2 Bcf per thousand foot. Three additional WDA Utica wells are scheduled to be online late this calendar year. But unless we are completely surprised, we are now planning to move to full WDA Utica development by the end of our next fiscal year. Our Utica development program will begin on currently producing Marcellus pads in order to leverage our existing upstream and midstream infrastructure to drive capital, operational and marketing efficiencies. The ability to return to producing pads to drill Utica development wells while utilizing existing Midstream infrastructure is a tremendous economic advantage for our company. We now expect to flow anywhere from 2 to 3x as much gas through our Gathering system versus our original estimates, amplifying the returns of our integrated Upstream and Midstream businesses. In terms of our fiscal '18 guidance, we are now forecasting higher capital expenditures ranging between $275 million to $325 million. In Pennsylvania, we'll spend between $240 million to $208 million (sic) [ $240 million to $280 million ] around $60 million more than we'll spend this fiscal year at the midpoint. The key drivers for this increase include utilizing a 2-rig program for a full year and drilling and completing a greater number of 100% working interest wells. One rig will focus on the WDA, drilling both Marcellus and Utica wells, and the other rig will be active in the EDA, drilling Marcellus wells in Lycoming and Utica wells in Tioga. We have 12 more Marcellus wells to complete in our IOG joint development agreement and those are currently scheduled to occur during the first half of 2018. Net production is expected to range between 185 to 200 Bcfe, a forecasted increase of around 10% year-over-year. Our fiscal '18 production forecast, however, assumes no curtailment throughout the year. We currently estimate between 30 Bcf to 40 Bcf available for sale into the spot market, so obviously, depending on pricing, these volumes are at risk for curtailment. However, with projects like Columbia's Leach XPress and ETP's Rover forecasted to go in service later this fall or early next year adding almost 5 Bcf per day of new capacity, we expect in-basin pricing will be more attractive and curtailments will be more modest over the last couple of years. We approached fiscal '18 with 90 Bcf of production locked in physically and financially at a realized price of $2.61 per Mcf. In addition, we have another 46.5 Bcf of production with basis protection through our firm sales portfolio. While realized prices are down somewhat from fiscal 2017, we are very pleased with our position and that these prices generate very economic returns for both our Utica and Marcellus development programs. Looking out 3- to 5-plus years, you'll note in our IR presentation published last night that, we have been busy securing additional firm sales to support our 10%-plus per annum production growth target. I think we're in great shape to fulfill this commitment with our 2-rig program and our marketing portfolio. [indiscernible] production to be around 20 Bcfe, much of our development activity next year will continue to focus in Midway Sunset, both in our legacy properties and on our new farm-in opportunities at Pioneer in South Midway and [ 17 N ] in North Midway. California continues to be a great business for us, with stable production, modest growth opportunities and steady cash flow. And with that, I'll turn it over to Dave.

Thank you, John. Good morning, everyone. National Fuel's third quarter consolidated earnings were $0.69 per share, an increase of $0.01 from last year's operating results, and right in line with Street consensus. Last night's release is a good job describing the major year-over-year variances, but there are a few items worth noting. Starting with Seneca, per unit LOE has trended higher in recent quarters. This is solely related to our California operations where, as John said earlier, we increased work overactivity and started new steam floods at some of our recent farm-in properties. LOE per unit in Appalachia is flat year-over-year. We expect steaming cost to remain at an elevated level for the next few quarters. Once the formation heats up, steaming expense should moderate, which combined with increased production in the East should cause our consolidated per unit LOE to return to a more normalized level. DD&A was $0.64 per Mcfe for the quarter, down $0.07 from the prior year, partially as a result of the ceiling test impairments that were recorded throughout fiscal '16. Over time, depending on service cost inflation and the timing of reserve bookings, we expect our long-term DD&A rate will settle in the $0.70 per Mcfe area. Turning to the regulated businesses. Revenue in our Pipeline & Storage segment was down year-over-year for 2 reasons. First, lower tariff rates were in effect this year as a result of rate case settlements at both Supply Corp. and Empire. As a reminder, Supply's rate case settlement in 2015 had a 2% step-down in tariff rates in November of '15 and again in November of '16. Empire settled the Section 5 rate proceeding last summer that similarly lowered some of its tariff rates, with the first step-down occurring this past October and another again this coming October. The second driver of lower revenue was a decrease in short-term revenues on our system, which for the most part we had expected. Now for example, over the past few years, as certain producers have grown into their firm transportation capacity commitments on our system, we've been able to generate a modest amount of additional revenues from secondary transportation services. Today, as we had expected, those producers are now generally using 100% of their capacity, which has largely eliminated that incremental revenue opportunity. In the Utility, in April, the New York Commission issued an order approving a $5.9 million rate increase. Given that we're in the summer months, the rate order did not materially impact third quarter earnings. Looking to the remainder of the year, we're tightening our fiscal '17 earnings guidance to a $3.25 to $3.35 per share. The details supporting this range were included in last night's press release and are not materially different from our prior guidance. One thing of note, given the general sustained improvement in spot prices, we're no longer forecasting production curtailments. Our updated fiscal '17 production guidance of 170 to 180 Bcfe, assumes about 5 Bcf in spot sales for the fourth quarter. Turning to fiscal '18. We're initiating preliminary earnings guidance in the range of $2.70 to $3.05 per share. Substantially, all of the projected drop in earnings is attributable to the exploration of natural gas and crude oil hedge contracts that have been put in place in a higher commodity price environment. Heading in a positive direction, as John mentioned earlier, Seneca's production for 2018 is expected to be in the range of 185 to 200 Bcfe, at the midpoint of 10% increase over our fiscal '17 expected production. From a NYMEX perspective, we're forecasting $3 per MMBtu for gas and $50 a barrel for oil, and both of these are generally consistent with the forward strip. We're fairly well hedged heading into the start of the fiscal year with 52% of our gas production hedged and 45% of our oil production hedged. Unfortunately, because of the contracts that rolled off, we're hedged at a lower price. Compared to last year, we expect after hedging natural gas and crude oil prices, will be lower by about 40 Mcf and $4 a barrel, respectively, which will impact earnings by about $0.55 per share. Again, this drop in hedge price is by far the largest driver of next year's earnings change. As with our fourth quarter guidance, we're no longer forecasting curtailments. At the midpoint, our guidance assumes 30 to 40 Bcf of natural gas, spot sales at a price of $2.40 per MMBtu. Spot pricing in Appalachia has moved around a fair amount over the past year and is difficult to forecast, but the $2.40 per MMBtu that we're using is generally in line with our average spot sales during fiscal '17. At the end of the day, variability in spot prices would be a significant driver of earnings volatility. As a frame of reference, a $0.25 difference in spot pricing would impact earnings by about $0.06 per share. We expect Seneca's unit costs in fiscal '18 will be similar to fiscal '17. As I mentioned before, there are some modest upward pressure in LOE due to increased work over and steaming activity in California. However, due to increased production in the East, we're forecasting LOE per unit to be more or less flat year-over-year. The increased production will likely drive G&A per Mcf a little lower and depending on service cost inflation in the timing of reserve adds, it's possible, DD&A could be a couple of pennies higher, but all-in, we don't see much of a year-over-year variance in Seneca's per unit operating costs. Seneca's increased production guidance of 185 to 200 Bcfe will drive a corresponding 10%-plus growth rate in the Gathering segment revenues. As a result, we expect Gathering revenues for 2018 will be in the range of $115 million to $125 million. In our Pipeline & Storage segment, we're expecting revenues to be flat year-over-year at about $295 million. The Line D project will add revenues, but that'll be offset by the rate settlements I mentioned earlier and other normal contract activity. Obviously, we planned on Northern Access driving near-term growth in this business and with its delay, our expectations have been tampered. Nevertheless, as we look to 2019 and beyond, our Empire North project, the further expansion of the Line N system and the continued modernization of our system should provide long-term growth for the pipeline business as we continue to work the regulatory challenges for Northern Access. At the Utility, our guidance reflects a return to normal weather, which should add $7 million to $8 million for our margin in Pennsylvania. Recall that, unlike New York, Pennsylvania, does not have a weather normalization mechanism. Our guidance also reflects the full impact of the $5.9 million rate award mentioned earlier. Operating expenses, including O&M, depreciation and property taxes are expected to increase by about 2% to 3% across our regulated subsidiaries. Several factors are driving this increase. O&M is expected to increase mostly due to higher personnel-related costs, including labor, health care, and retirement benefits. Higher spending on safety and on our pipeline integrity program is also a factor. Property taxes and depreciation expense will increase largely as a result of plant additions over the last couple of years. Switching gears to capital. Complete details are in the earnings release, so I'll only hit the high points. Our fiscal '17 forecast is largely unchanged. A small decrease in the midpoint is caused by the timing of spending between fiscal years. For fiscal '18, our initial projection is for spending between $535 million and $645 million. At the midpoint, a slightly more than $100 million increase over fiscal '17. John already touched on the increase in Seneca's planned spending, so I'll focus on the other businesses. Pipeline & Storage spending is expected to be up by about 20%, largely due to an increase in infrastructure and modernization spending. We typically target for about $40 million per year in these projects, but the past 2 years, they've been well below that level. We're tackling a few larger projects this year, which will cause modernization spending nearly double. In our Gathering business, we expect capital to be in the range of $60 million to $80 million. This increase is largely driven by Seneca's second rig and various infrastructure additions needed in advance of Seneca's Atlantic Sunrise capacity becoming available. At the Utility, spending should be consistent with fiscal '17 within a range of $90 million to $100 million. From a financing perspective, our cash from operations should exceed our capital spending for both fiscal '17 and '18. When you take into consideration our dividend, we expect a modest cash need which will be met from the cash we have on the balance sheet. We have a $300 million debt maturity in April of 2018 and another $250 million in 2019. Both of these issuances carry higher coupon rates, so in the coming months, we'll be evaluating our strategy to manage these maturities. In conclusion, National Fuel's in great shape. At a 2-rig program, Seneca should be able to grow production by 10-plus percent per year for the next several years, which will drive earnings in both our E&P and Gathering businesses. At the regulated businesses, the Northern Access -- the delay in Northern Access is certainly disappointing, but the opportunities on the Empire and Line N systems will be sources of future growth. While 2018 earnings will not benefit as much as in prior years from our hedge book, we're very well positioned to deliver long-term growth and strong returns in the years to come. With that, I'll close and ask the operator to open the line for questions.

[Operator Instructions] And your first question comes from the line of Graham Price with Raymond James.

Just wanted to get a sense of timing kind of around the 12 remaining joint development wells. I know that you're targeting first half '18 for those -- to completed those, but -- we're just kind of wondering if you think those will be kind of spaced evenly? Or maybe weighed towards 1 quarter or another?

Yes, absolutely. The timing will probably be more towards the back half of that -- by our third fiscal quarter.

Okay. That's helpful. And then just real quick for my follow up. Looks like you've done a really nice job in filling in those firm sales since the Northern Access delay. But looking at Slide 22, did see that there is a little bit of a dip there right before Atlantic Sunrise comes on, and so just -- kind of wondering if you've seen opportunities to fill in that gap?

Yes, the -- sort of a bit on purpose is where prices have dipped a little bit, so we're -- as we get closer to winter months, we're going to look for opportunities to layer in additional sales. But we are also waiting to get a bit more visibility related to the turn-on date to Atlantic Sunrise. And as we begin to see -- get more information about when that's actually to come on, it'll give us a better perspective in terms of how we want to fill in those gaps.

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

I had a couple different topic area that I want to hit and run, but if I could start with the Gathering CapEx, I know last night, you had mentioned, I know we've been talking about for a couple quarters the prospect of potentially a Utica transition and the opportunity to leverage some of the spending that's already been put in the ground in terms of Gathering infrastructure, et cetera. So looking at -- I know you have some tie-ins to, I think, TGP 300, the Gathering CapEx number for '18, up slightly year-on-year, obviously your production is up as well. Just wondering how we should see, I guess, over time as you transition on John's schedule to Utica to think about what that ratable number might be on Gathering if you're assuming 10% production growth. And then also a very related question, where we might see those efficiencies show up? Whether they'd be all in the Gathering division? Or does Seneca benefit at all from that? If you could talk about the relationship between the 2 groups as it pertains to utilization of shared infrastructure over time.

Sure, Chris. Dave has -- we've got kind of a Gantt chart, if you will, with respect to all that spending. So I'll let him address that timing.

Yes. And Chris, I think, you'll see 2018 is going to be a little bit higher largely because we're going to be building a compressor station on the trial run system in advance of Northern Access coming online, that'll be of a decent slug of capital. When you think longer-term on Gathering CapEx at a 2-rig program is more likely in the -- call it $35 million to $40 million area on an annual basis, but their share will be a little higher because of that compressor station.

Okay. And Dave, that was ahead of the [ Blackstone ], right?

Yes. And then in terms of where we'll see the efficiencies, I think it will largely be on Seneca.

So is the thought that their rates sort of [indiscernible] lower as they share?

I'm sorry, Chris. I said that completely backwards. It -- we'll see it on Midstream, where we'll likely keep the rates the same on Midstream, so you'll see outsized cash flows and earnings on the Gathering side of the business.

Okay. Relative to the amount they're spending if it returns simply in [indiscernible].

Right.

Got it.

Right. Their return on capital should go up meaningfully.

And Chris, this is John. In terms of Seneca's perspective, there will be some savings returning to these pads that we estimate roughly $300,000 per well, since they're returning to pads that have already been built and all the production equipment is there. So there will be some improved efficiencies there as well.

Okay. Wonderful. I guess, if I could pivot then to the pipeline. Dave, you had mentioned, obviously, we see a tick-up in the maintenance integrity monetization spending. You had mentioned some underspending perhaps relative to sort of a normal cadence. The last couple of years, you obviously had some projects. Just wondering -- couple questions on that. One, sort of how do we think about the decisions around that allocation? Is there a formal process you go through with FERC on that? Is that company discretion in terms of which projects happen in which order? And then I had a separate question on Northern Access -- sorry, on Empire North.

Yes. So from a -- how we assess which projects that we're going to build, it's -- our engineers are regularly looking at our system and prioritizing the areas that we think are in need of modernization. In terms of interaction with FERC, to the extent that the projects are big enough, we have 7(c) application processes that have to be followed, but there isn't a specific direction from FERC on which parts of our system to attack before others.

No, that does help. And I guess, with regard to that workload, do you wind up with any system enhancements as part of that effort? Or is that simply making sure that the system -- that the aged, either the most aged or in the most critical areas that you have assets in place that are capable of operating safely all the time?

Yes. I mean, typically, to the extent that there's a market, we'd look to use that modernization in conjunction with the expansion efforts. So if you go back over time, a lot of the work that we did at -- on Line N in the [ Transco ] area involve both expansions and modernization.

Okay. And then, I guess, with regard to Empire North, I think, it was Slide 39. Congrats on getting the precedent agreements signed. I know you were talking about that ever since the open season. Saw the CapEx come down, $185 million to $135 million. I'm assuming that's just the scope change. It looks like there was less of an interest going to Hopewell, but I just want to make sure I was interpreting that correctly.

Yes. We have had a -- there was a wide variety of sizes of the project and we honed in on the 205 million a day and are sharpening our pencils on capital estimates and are coming into the $135 million area.

Yes, the -- so the big change in that CapEx would be going from the original conception, 300,000 dekatherm per day project would have required 3 compressor stations going down to 205,000, we get it down to 2 compressor stations.

Okay. That's very helpful. I guess, one final question from me, and I will hop back in the queue, is, more of a market-based question, philosophical question. We've seen some M&A in the Northeast clearly on E&P combinations. I guess, right now, we have most notably rise in EQT, seen some acreage swaps on the E&P side, we've also seen some Northeast E&P companies from a share price perspective under tremendous pressure. And so I'm just wondering, if assets were to -- Midstream assets or additional reserve opportunities were to fall out from any of that, I guess, two questions. One, how do you see that landscape? Second, what's your appetite to participate? And then we've also seen more recently some joint ventures on pipes I guess, again most recently would have been Blackstone and Rover. I know with the delay on Northern Access, you've talked about opportunities to maybe get on to some other systems that are being advanced through the FERC process. I'm just wondering if there's any appetite or ability to participate on a joint venture basis in that. So kind of 2 parts, but same type of question with regard just to appetite or even how you see at the landscape?

So with respect to your first point, yes, you always see some moving around of some assets. As we look at it, Chris, we've -- first of all -- first and foremost, want to look at, making sure we've got enough inventory to fill up the capacity that we have committed over the next 5 to 10 years. So yes, we're always looking at various acreage tracts that fill in some of the spots that adjoin our existing production and drilling activities. And trying to plan that out far enough in advance so that we make sure we have that inventory available. So John's team is constantly looking at that aspect. With respect to major M&A, I wouldn't necessary see that on our schedule, just because we have a bunch of our own acreage available that we need to -- most of it's fee, so we don't have to worry about it expiring, but we already have that on our books. With respect to JVs on pipelines, yes, that always is another aspect that we like to think of projects and things where it solves problems for both entities in terms of joining up with somebody who either has capacity or market, and isn't just building a pipeline but can also bring production along with it or a market on the other end. So yes, we continue look at those.

Your next question comes from the line of Holly Stewart with Scotia Howard Weil.

Maybe first, John, you mentioned some recent curtailments in Northeast, PA. I'm assuming that means FY 4Q, but could you give us maybe just a little bit of color on that? And then, yes, you mentioned also that there is nothing in the guide for curtailments for '18, so is there a pricing point? Or some way for us to sort of think about that on a go-forward basis?

Sure. The recent curtailment has only been 2 or 3 days across the last couple of weeks on certain receipt points, so wasn't even across the entire system as more focused on certain receipt points, so a bit more sporadic. And to date, has not really been a large shift in volumes. In terms of next year, I don't like to talk about at what price we curtail, because I know there's a lot of other producers that are out in the same area. We do have price targets that we do shut in, but that's just something I'd prefer not to talk about.

Yes. Fair enough. Maybe also kind of shifting to the Utica. I thought we have talked about, last quarter, there were about 3 wells that were completed, either late last quarter or end of this quarter. I know you mentioned one, and you increased the EUR per thousand based on that. Is there any color on the other 2, if I had that right?

Yes, actually, there is. In terms of EUR, there has been -- there's 5 wells now producing and in terms of EUR, 3 out of our first 5 should range anywhere from 1.8 to just over 2 Bcf per thousand foot. In fact, 2 of them we think now will be over 2 Bcf. The other 2 wells, we just brought on about 3 months ago, and they're estimated to range between 1 and 1.4 Bcf. And the difference here is, we believe this decrease occurred because we brought both of these wells online much more aggressively. And we're now thinking that, we may have actually damaged the reservoir little bit, most likely by crushing sand. The reservoir pressures in the Utica are well over twice that observed in the Marcellus. And again, since we're using that standard white sand rather than high strength proppant, there is increased risk for that type of damage. So these wells are still larger than what we saw, but a little bit less than the other 3. Obviously, now we recognize that the drawdown management is critically important for the success of this -- of these wells. And as we move forward, we're just going to be more cautious and our latest wells are perfect example of that.

Okay, okay. That's perfect. And then maybe one final one for Ron. You highlighted that if the FERC picks up your argument on Northern Access, the timing could be expedited maybe pretty significantly. Is the way to think about that we should just be looking at the Millennium appeal that's going on right now?

Yes. I guess, that's one probably pretty good indication. The other thing though is the -- obviously, without a quorum for the last 6 months, there's a pretty big backlog. So I would expect their first order of business would be getting through the certificate proceedings before they start reacting to the rehearing orders. So there's a couple of things going on there, but yes, I think the Millennium, their handling of Millennium's request would be a pretty good indication. And then you have to ask yourself, if that's going to happen before the end of August, when DEC might be expected to actually rule on that Water Quality Certification.

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

On Slide 21, there is a range of Utica locations of 125 to 500-plus. Can you talk about what encompasses that pretty wide range?

Yes, absolutely. The 125 are actually locations that we'll be able to return to currently producing Marcellus pads. So that is where the minimum comes from. And then the 500 plus is -- our most recent well was in an area called Rich Valley, and as I said before, that's performed very well, and we think there'll be some running room as we move to the Southwest along that area, and if there is, it adds inventory very quickly.

And that gets you to the 500 by just including the Rich Valley area?

No. Rich Valley and then additional acreage as we move to the Southwest.

And we'll be drilling one more appraisal well even further to the Southwest during fiscal '18, and that will pretty much -- at least at that stage, it'll give us a sense of what to expect between Rich Valley and that well.

Okay. And then, in the past, some of the companies have moved to the Utica program have talked about maybe having to build a different Gathering system. As I understand it, you don't have to make any changes to your system, it's just using the existing infrastructure, no additional CapEx?

I wouldn't say no additional CapEx, it'll be minimal. We'll be increasing the size of some of these pads. There'll be a little bit of CapEx on the Midstream side, but a fraction of what the initial costs were. But no, we will not have to change -- use a separate pipeline system.

Because each of our pads have both high and low pressures.

Okay. That's what I needed. And then finally, given the pad drilling, should we expect any lumpiness to '18 production across the course of the fiscal year?

Yes. Whether we're drilling Utica or Marcellus wells, we typically drill anywhere from 6 to 12 wells per pad. And in some cases, now we're drilling some 10 to 12 Marcellus wells and 3 to 4 Utica wells. So yes, there will be lumpy production growth across the entire year.

Is it more back-end loaded or?

No. It's -- no, looks like we reached in our -- in terms of our forecast, looks like peak production is around the January, February area, and then again, around the May, June, July area.

Great. So maybe fiscal first quarter is a little softer?

Yes.

Due to technical difficulties at the beginning of the webcast, a full replay of today's call will be available at approximately 2:00 p.m. Eastern Standard time by accessing the archive on the National Fuel Investor Relations website. I will now turn the call back over to the presenters for final remarks.

Thank you, Liandra. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be made available at approximately 3:00 p.m. Eastern Time on both our website and by telephone and will through the close of business on Friday, August 11. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1 (855) 859-2056, and enter the conference ID number, 51109130. This concludes our conference call for today. Thank you, and goodbye.

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