National Fuel Gas Company (NFG) Q4 2018 Earnings Report, Transcript and Summary

Good morning. My name is James and I will be your conference operator today. At this time, I’d like to welcome everyone to the Q4 2018 National Fuel Gas Company Earnings Conference Call. All lines have been placed on mute to prevent any background noise. And after the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] I’d now like to turn the call over to the Director of Investor Relations, Ken Webster. Mr. Webster, please go ahead.

Thank you, James, 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 fourth quarter fiscal 2018 earnings release and November 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 Jefferies Energy Conference, later this month. 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. We finished our 2018 fiscal year with a strong quarter; and looking forward, we expect fiscal 2019 will be a good year too. We’ve got a lot to keep us busy, and I’ll give some thoughts on the various activities in our major operating segments, and how they fit within our overall plans for the future. Dave Bauer and John McGinnis will also provide some more color on the financial results detailed in last evening’s earnings release, before we open it up for questions. More than half of our capital expenditures in fiscal 2019 will be directed toward our upstream exploration and production business where we will continue to keep three drilling rigs active. Well results in Seneca’s Utica drilling program continue to meet our initial projections, and those results were instrumental in increasing our proved reserves to 2.5 trillion cubic feet equivalent. We are continuing to look at fine-tuning some of our well designs to maximize the per well reserves while keeping within our drilling budgets. While 2.5 trillion cubic feet equivalent is the highest level of year-end reserves that Seneca has ever reported, what’s equally impressive is that 70% of those reserves are proved developed reserves with only 30% in the proved undeveloped category. The three rig drilling program that is now focusing on 100% Seneca-owned wells is bearing fruit in terms of growing both, production and cash flow. In addition we’ve got a lot of running room with plenty of well locations across our large acreage position in Pennsylvania. Since the bulk of that acreage is owned in fee with no lease expirations to contend with, we’ve taken the conservative approach to drill it only when we have a line of sight to pipeline capacity that is available to get our production to market. Speaking of new pipeline capacity, we’re pleased that Transco’s Atlantic Sunrise project started up last month and is flowing at full capacity. Seneca is shipping its full 189,000 dekatherm per day on the pipeline, and we have an array of contracts for all that gas, priced to premiums to NYMEX. Following our usual practice, we detail their production estimates and price assumptions in our slide deck that we posted last night. Given that approximately 70% of our projected production has some type of hedge for the fiscal year and an additional 15% as basis protection, we’re very comfortable with our 2019 earnings outlook. That will continue to be the plan for Seneca. We’ll maintain a steady drilling program and follow our hedging program to achieve price certainty over the coming year. With three active drilling rigs, we plan to grow production and reserves, allowing Seneca to make a strong contribution to earnings. As you know, the operations of our Gathering segment closely mirror what we’re doing at Seneca. However, our 2019 fiscal capital expenditures for gathering in the Western Development Area will be very modest. Seneca’s production from its new Utica wells will be utilizing the gathering pipelines that were already built for our Marcellus pads. The ramp-up of Utica production volumes through our gathering system will translate into meaningful cash generation and increased returns on investment on a consolidated basis. Switching to our interstate Pipeline and Storage business, we had a number of positive developments that set us up nicely, moving forward. Regarding our expansion projects, things are moving along well. Earlier this week, we received a positive environmental assessment or EA, on our 205,000 dekatherm per day Empire North project. That should put us on track to get our FERC certificate, late this winter or early spring 2019. So, we are targeting an in-service date sometime during the second half of fiscal 2020. On another pipeline project, both National Fuel and Transco are working on their respective pipeline segments that we put together to move 330,000 dekatherm per day of Seneca’s production from both, our Western Development Area and Eastern Development Area to premium Zone 6 markets on the Transco system. National Fuel’s project is our FM100 project and Transco’s expansion is their Leidy South. The combined FM100, Leidy South project is another example of the benefits of our integrated structure. Seneca will develop its large free acreage position in the WDA, flow our gas production through our gathering and compression assets, and while Seneca has committed to Transco as the developer of the project, National Fuel Gas Supply Corporation will invest in new facilities to provide part of the path and lease capacity to Transco, generating significant incremental annual revenues. We continue to target a late calendar 2021 in-service date for these projects. Our Northern Access project received a boost by way of a favorable determination by the Federal Energy Regulatory Commission, but the New York DEC exceeded their allowed time to either approve or deny a water quality certification. While we’re still a couple of years and likely a few legal challenges away from constructing this project, it’s a giant step in the right direction. We anticipate that this will likely be a 2022 project. All of these projects are great projects that provide significant rate base and earnings growth for our pipeline business and provide needed outlet for Marcellus production in central Pennsylvania. In our utility business, both our customers and state regulators recognize that it’s important to invest in our pipelines to keep them safe. I expect that we will be investing $90 million to $100 million a year in utility rate base for the foreseeable future to maintain the safety of our pipeline network. In New York, we have a tracking mechanism that allows us to get that new infrastructure into rate base without having to wait for a full-blown rate case. So, we can see modest margin growth attributable to those investments. When you look at National Fuel’s overall operations, our approach to operating and financing our business is pretty straightforward. We maintain a conservative balance sheet, pay an attractive dividend, and focus on living within cash flows over the medium term, all while retaining the flexibility to spend on growth projects in the pipeline and exploration business. Many of our peers are just turning to such a strategy, but we’ve been living it right along. Over the past three fiscal years, our cumulative cash from operations and asset sales exceeded our net capital expenditures by nearly $500 million with roughly $400 million of that amount returned to shareholders through our long-standing dividend practice. Where we sit today, our opportunity set is the best that it’s been in a long time. We have a significant opportunity to invest in our regulated businesses, expanding and modernizing our transmission, storage, and distribution assets with the potential to deploy $1.5 billion in the next four to five years. Seneca’s acreage position is one of the largest in the basin. And as a proven low cost producer with the vast majority of our natural gas rights owned in fee, we have the ability to capitalize on opportunities as pricing and returns warrant. Our codevelopment of the Marcellus and Utica along with owning and efficiently operating the associated gathering infrastructure, allows us to achieve returns in excess of standalone producers. We believe we have a great growth plan for our integrated businesses, but we remain committed to a strong balance sheet. And as you’ve seen in the past, we have the flexibility to adapt to changing market conditions. Now, I’ll turn it over to John to discuss Seneca’s operations.

Thanks, Ron. Good morning, everyone. Seneca produced 47.3 Bcfe during the fourth quarter compared to 40.4 Bcfe in last year’s fourth quarter. Total annual net production was 178.1 Bcfe, a new annual high for Seneca and about a 2.5% increase year-over-year. In the East, we produced 43.2 Bcfe during the fourth quarter compared to 35.6 last year, a 21.5% increase. In California, we produced 682,000 BOEs, down around 14% from last year’s fourth quarter. And this decrease was largely driven by the sale of Sespe earlier this year and natural decline at several of our fields. Capital expenditures for the year were at $356 million, just under the midpoint of our guidance. Expenses on a per unit basis were all within guidance. For the year, our proved reserves increased by 369 Bcfe or 17% to just over 2.5 trillion cubic feet equivalent. Utica reserves, driven primarily within the WDA, more than doubled year-over-year and now account for nearly 20% of our total reserves. As we move forward over the next few years, in conjunction with our increased WDA production, this percent will continue to grow. And finally, we continue to drive down our three-year average F&D costs, now at around $0.74 per Mcfe. So, moving to fiscal 2019 guidance. We are now forecasting capital expenditures to come in a bit lower, now ranging between 460 to $495 million. California is expected to be around $25 million and Pennsylvania between 435 to $470 million. Net production is expected to range between 210 to 230 Bcfe, a forecasted increase of around 24% year-over-year at the midpoint. As stated last quarter, we will continue with the three-rig program, two rigs active in the WDA, drilling mostly Utica wells on existing CRV pads, and a single rig in the EDA, drilling Utica wells in Tioga county and Marcellus wells and in Lycoming. Atlantic Sunrise, which provides important takeaway from our Lycoming assets, went into service during the first week of October. Our firm transportation on this pipeline is around 190 million per day, all of which has been sold at a premium to NYMEX over the next five plus years to downstream entities and third-party marketers. In addition, as we discussed previously and recently announced by Williams, Seneca has entered into a new firm transportation commitment for 330 million a day on the Transco system. The Leidy South expansion project will provide a critical outlook for our WDA Clermont-Rich Valley production into premium markets connected to Zone 6 of Transco’s interstate pipeline system. One of the unique attributes and key benefits to Seneca is that transportation path allows flexibility on how we fully utilize the capacity. We have the optionality to flow our production from both our CRV and Lycoming acreage to fill this new firm capacity, ensuring long-term out-of-basin market access from Seneca’s two largest development areas. Additionally, Seneca will utilize affiliated NFG gathering infrastructure to reach the Transco system, leading to strong consolidated returns. This capacity could be on line as early as fourth calendar quarter of 2021. In the WDA, we remain at 11 Utica wells producing. And given our results to-date, our CRV Utica type curve continues to assume an EUR of 1.7 Bcf per 1,000-foot. We have 11 additional CRV Utica wells scheduled to come on line during the first half of fiscal 2019. So, as we enter our third quarter, we should have sufficient producing inventory to further optimize drill target and completion design. We enter fiscal 2019 with the pricing for 149 Bcf or 73% of our East division gas production locked in physically and financially at a realized price of $2.43 per Mcf. We have another 28 Bcf of firm sales providing basis protection. So, over 85% of our forecasted gas production is already sold. We currently estimate that we’ll sell around 27 Bcf into the local spot market. But, depending on in-basin pricing, these volumes are potentially at risk for curtailment, which could reduce our forecasted production range. That being said, as a result of our current firm sales portfolio, we have already locked in net production growth of almost 9%. And therefore, we are in excellent shape and well-insulated, should gas prices fall as we exit this winter. And finally, in California, around 77% of our oil production is hedged at an average price of $57.57 per barrel. With that, I’ll turn it over to Dave.

Thanks, John. Good morning, everyone. Last night, National Fuel reported fourth quarter operating results of $0.49 per share. Though a little below Street consensus, these results were right in line with the guidance we provided last quarter. Our E&P and gathering businesses had good quarters. On a combined basis, the operating income of these businesses increased by $1 million over last year. As John mentioned earlier, Seneca’s production was up 17% compared to the prior year and its operating expenses were all in line with our expectations. In addition to benefiting Seneca, this production growth drove a 14% increase in gathering revenues during the quarter. Unfortunately, as in the first three quarters, the expiration of favorable hedge contracts caused a $0.46 drop in realized natural gas prices which offset the benefit from higher production. Going forward, quarter-over-quarter comparisons of realized natural gas prices should be much more muted, given our strong marketing, portfolio and hedge position. At the pipeline business, O&M spending increased by $2.8 million over last year. As I discussed on last quarter’s call, in the near term, we expect to see significant increases in our compressor maintenance and pipeline integrity spending due to cyclically higher than normal required levels of activity. Some of that activity started in the fourth quarter of fiscal 2018, leading to the increase in O&M spending. This maintenance spending offset what was otherwise a good quarter for the pipeline business where revenues were up $2.6 million or nearly 4%, as a result of both our Line D Expansion that went in service last November and our storage acquisition that closed this past May. We also saw some nice demand for short-term service on our systems. Utility margin was down versus the prior year’s fourth quarter, as a result of a transition to a new low income program in New York. Under the old program, low income discounts were reflected in customer’s bills, based on usage. Effective April 1st, the start of our new rate year, we switched to a new program under which discounts are granted more evenly across the year. As a result, the fourth quarter, which is a low-usage quarter, reflects about $2.5 million more in discounts than in the prior year. This is really just a timing issue. The higher usage quarters in the first half of fiscal 2019 will see a benefit from this change. Also at the utility, the fourth quarter saw an increase in O&M that was related to bad debt expense. In fiscal 2017, we recorded approximately $3 million in adjustments to reduce the utilities reserve for bad debts. This adjustment, which lowered fiscal ‘17 O&M expense, did not recur in fiscal ‘18. With respect to income taxes. Our consolidated full-year effective tax rate was 25%, right in line with our expectations. During the quarter, there were a number of tax related adjustments across our operating segments, many of which relate to further impacts of tax reform, particularly the IRS’ announcement in August that a 100% bonus depreciation would be available for the regulated companies for the 2018 tax year. In addition, our tax restructuring among our E&P and Gathering subsidiaries created one time favorable impacts during the quarter and should lead to significant state cash tax savings moving forward. Looking to next year, we expect our consolidated effective rate will remain in the 25% area. Turning to guidance. We now expect fiscal 2019 earnings will be in the range of $3.35 to $3.65 per share, at the midpoint, a $0.05 per share increase from our previous guidance. This was driven by two principal items. First, we refined a few pricing assumptions in the E&P business. Our forecast now assumes WTI will be $70 per barrel and NYMEX natural gas prices will be $3 per MMBtu in the winter and $2.65 in the summer. Also, on the recent strength of pricing in the basin, we are increasing our winter spot price assumption by $0.10 to $2.50 per MMBtu. We’re keeping our spot price assumption at $2. Second, we finalized our fiscal 2019 O&M budgets across the system. On our last earnings teleconference, I said that Pipeline and Storage O&M was expected to increase by 5% to 10% over fiscal 2018 levels, again, as a result of some required compressor maintenance and pipeline integrity work. We’ve refined our estimates and now expect the increase will be toward the lower end of the range, say in the 5% to 7.5% area. On the capital side, we’re lowering the midpoint of our range by approximately $30 million to a range of $725 million to $810 million. On the E&P side, as John mentioned, spending will be slightly lower due to permitting delays in California. Pipeline and Storage capital was reduced by about $25 million to reflect the change in timing of the acquisition of materials for our expansion projects. With the delay in Northern Access, two compressor units that were purchased for that project will instead be used in the Empire North project. In addition to preserving near-term capital, this will allow us to potentially put a portion of the Empire North project in service a little ahead of schedule if we can reach an agreement with project shippers. We will then procure compression for Northern Access once we have greater clarity on the timing of construction. Based on the midpoints of our updated earnings and CapEx guidance, we expect our funds from operations should cover substantially all of our capital expenditures for fiscal 2019. Adding the dividend and working capital to the equation, we expect to have a financing need in the $150 million to $175 million area that can be met with the cash we had on the balance sheet at the end of September. Looking to 2020, the construction of the Empire North project and ongoing pipeline modernization program will cause the outspend to grow, but at this point, we expect to be able to fund it within our balance sheet. We’ve been pretty active in the financing markets since last quarter’s teleconference. In early August, we issued $300 million of 10-year notes, the proceeds from which were used to fund the early redemption of a $250 million May 2019 maturity. Since then, treasuries have moved up meaningfully. So, this looks like a really good transaction. The 2019 bonds were the highest coupon debt in our portfolio. Next year, we should see a significant savings in interest expense as new issuance carries an interest rate that is 400 basis points lower than the 2019’s. Also, last week, we took advantage of the continued strength in the bank loan market and amended our $750 million committed credit facility to extend the tenure for another five years through 2023. There were no changes to the pricing structure of the facility. In our current credit rating, borrowings under the facility would be made at LIBOR plus 110 basis points. The facility is undrawn today. Together with cash on hand, we have nearly $1 billion of short-term liquidity going into fiscal 2019. In closing, fiscal 2018 was a good year for National Fuel, and the coming years are looking even better. Seneca’s three-rig program will drive production and gathering revenue growth in the 15% to 20% area; the Empire North project in 2020; and the FM100 and Northern Access projects in 2021 and beyond will be game changers for the pipeline business. And lastly, our modernization program at the utility should drive a modest amount of growth in a business that’s been relatively flat in recent years. With that, I’ll ask the operator to open the line for questions.

[Operator Instructions] And your first question comes from the line of Graham Price from Raymond James. Go ahead, please. Your line is open.

Hey. Good morning, guys, and thanks for taking my questions. I guess, given that it’s year-end, just wanted to get a sense of where the annual base decline rate on existing production stands today. And then, maybe where you see that changing over time?

I couldn’t tell you across our basin what the annual decline rate actually is. But, I think, in terms of how it will change, the Utica wells -- let’s focus on the WDA where most of our activity is. The Utica wells there do have a shallower decline than the Marcellus wells, over the first year or two. And then, the two, both Marcellus and Utica at that stage tend to decline similarly, at similar percent on a year-over-year basis. So, as we drill more and more Utica wells, we will see a bit more shallower decline related to the -- as we develop that Utica program. But, then it sort of conforms to what we see related to the Marcellus as well.

Thanks. That’s definitely helpful. And then, for my follow-up, I was just curious to kind of get a sense of when we might see further delineation kind of in southern WDA area sort of near the Boone Mountain well?

Sure. I think, our next appraisal well is scheduled for our fourth quarter of this fiscal year or first quarter of 2020, and that will be located approximately 5, 10 miles north, northeast of the Boone Mountain well. So, it will be a year out, maybe a little bit less.

[Operator Instructions] Your next question comes from the line of Chris Sighinolfi from Jefferies. Go ahead, please. Your line is open.

Dave, I always appreciate the detailed remarks in your outlook. If we could, could we circle back to pipeline and utility operating cost for a moment? I know you had flagged this on last quarter. And I don’t know if I just misscalibrated your comments at that point for if spending shifted modestly from 2019 into 4Q. It seems like that might have happened, based on your comments. But, I guess, I’m curious if you could quantify -- if that did happen, if you could quantify the magnitude. And then, also, what drives the timing of when that spend has to happen?

Yes. Chris, there’s a little bit of spending that moved forward, but not a ton. I mean, may be 1 million or so dollars. And in terms of what’s driving the timing for our compressor units, it’s all based on the number of run hours. So, you have to do these overhauls every increment. And we just happen to have a number of our units, all reach those milestones within the same year. The other element is on the pipeline integrity side. We’ve got to do integrity assessments on a seven-year cycle. So, we take our whole system and split it into seven different components. It just so happens that fiscal ‘18 -- or excuse me, the work that we’re doing in fiscal 2019 is the highest year in that seven-year cycle. So, we’ve got a couple of things that are going against us on -- all on the same year, but then that should moderate as we get into 2020.

Yes. I guess, what I’m interested is that I think you had revised the O&M increase in the pipes to a range 5% to 7.5% year-on-year next year, which incorporates I guess both of those activities. And then, if we’d profile ‘20, how much would you estimate or help us guide, of that might come back up?

I guess, I don’t want to be overly specific on and I wouldn’t certainly expect a similar level of increase. I think, there’s a good chance that we’d actually have lower O&M expense in 2020 than what we will in 2019.

Okay. And then, I guess on utilities side in that regard, you talked about the transition of the low-income program in New York. I think that’s something you flagged earlier on in the year as well. But the $2.5 million that you had mentioned for fiscal 4Q as sort of a temporal shift when it’s recognized. Should we expect then the benefit perhaps in fiscal 1Q or 2Q ‘19, your higher activity and earnings quarter, so that utility would have -- the order of benefit would be very similar to that 2.5?

Yes. The level of discounts that are granted stay exactly the same, it’s just that instead of recognizing them kind of as volumes flow through the system, it’s going to be on a straight line basis. So, that’s going to have the effect of punishing the low volume quarters and helping the high volume quarters. But, you are thinking about it the right way.

Okay. And one more question on the utility, Dave. The bad debt has been something I think that’s been a bit of a tailwind as we’ve had very strong economic climate and low interest rate. But we have seen rates rising and we’ve seen articles about some of the credit card companies becoming a little bit more careful about their lending standards et cetera. So how much of bad debt expense is tied to rates or I guess better stated, what drives the assessment on that?

Yes. So the adjustment that we were talking about was made in the fourth quarter of fiscal 2017 and it didn’t recur in 2018. So when you go back to fiscal 2017 we had a pretty warm winter. And so customer bills were lower than we had expected. And so we accrued an amount of bad debt expense over the course of the first three quarters of fiscal 2017 that was higher than we actually needed. So we took that down in the fourth quarter of 2017. When you look at 2018, our level of bad debt expense or I should say the level of final bills and late bills really isn’t that different than what it’s been in the past. So we haven’t really seen much of deterioration in the credit or payment habits of our customers.

Okay, I misunderstood it. I think it was just really -- your comments were addressing the year-on-year change not a change on the customer base.

Right.

Okay, understood. Sorry about that. Okay, if I can ask just one or two more questions intended to John. Obviously, I realized the full Netherland Sewell reserve report is not out yet, we’ll wait for your K for that. But just curious, I think you had said in the prepared remarks that 20% or 500 BOEs now out of the reserve base is represented by Utica. Curious the detail -- a little bit more detail about maybe the type curves used by Netherland Sewell in assessing the Utica program and the Marcellus program, is that the same as what you’ve posted and discussed today? Or did they make any adjustments that we should be aware of?

Chris, it’s early in the process. As you know a lot of these -- the Utica wells have only been producing for two years or less. But we are very similar to what Netherland Sewell has posted, and you’ll see the detail as we -- once we release that information. It’s mostly WDA, is where we have the reserve increases. We do have some in 007, since we’re drilling and we’ll be bringing on some new Utica wells there as well. But really the driver is the WDA. Yes, there is -- early on in these programs, there’s a little bit of deviation, but as time goes on, it tightens up.

Okay. Deviation where they as the reserve auditor would tend to be more conservative than you?

It varies. Sometimes we tend to be a bit more conservative, sometimes they do.

Okay. And the time -- I guess you’ve had a shift in your program focus over the last year obviously toward more Utica development. Any comment -- I guess any help in explaining maybe the influence that might have had on what we’ll ultimately would see in this reserve report?

I’m not sure I understand that question.

Well, you obviously pivoted in terms of the focus of the program and I would imagine that would influence how they’re going to look at a five-year window of development activity for each of the regions.

Certainly, our focus in the WDA is going to be Utica. I guess, Chris, I’m still not sure I understand what -- where your question is here.

Well I was just -- I guess trying to gauge, John, year-on-year given the pivot in the program as Netherland will look that. I guess they’re tethered to one and the same type curve comment and how much to anticipate. I mean you obviously share with them a little bit more about your detail in terms of what you’re going to do longer term than maybe we see in your official financial forecasts. So I was just curious how much you might have deviated not only in terms of the type curve view, but in terms of the activity level on WDA versus maybe what they had thought you would do a year ago?

Yes. I’m not going to comment on that Chris. At some stage our Reservoir Engineering Group goes through this well-by-well about how on a well-by-well difference between each and every one between Netherland Sewell and Seneca is -- that’s something I would have to sit down and really walk through. So that’s just -- that’s a lot of detail that we typically just don’t get into. But suffice it to say that Netherland Sewell and Seneca are well within our boundaries in terms of how we look at the Utica.

Understood. Thanks for the time.

Your next question comes from the line of George Wang from Citi. Go ahead please, you line is open.

I just want to hone in on Utica. It seems that one of the biggest drivers was stock. So just in terms of D&C design just namely the drill and the competing design for Utica, can you give more color on whether you guys are still tweaking to find the best well spacing and landing zone? Just also the impact to potential well cost savings than the improving returns?

Sure I’ll touch on that. And as I said in my statement today, we’ll get into much more detail on that in six months as we continue to get more information. But right now, we’ve been testing and let’s begin at stage spacing. We’ve been testing between 150- to 200-foot stage spacing to determine if we see any impact to production. Obviously, if we move to 200-foot, that will be cost saving in terms of our -- on a cost per-well basis. We have also been testing target in our area there is -- we’ve been drilling within both lower Utica and then a little bit deeper in what we call the upper Point Pleasant. And over the next six months, we’ll have sufficient wells within both of those zones to, again, determine which -- where we see better production and, I guess, more effective fracking. As far as well spacing, we’re starting wide around 1,200-foot. And with time, once we lockdown the state spacing the target -- what target we’re going to focus on, then we can begin to look at whether or not we want to begin to tighten the well spacing up. But right now, at least for the near future, we’re going to -- we’ll be at 1,200-foot.

Got you. And for the WDA Utica, in terms of restricted drawdown, have you quantified a potential improvement to EUR just with a better draw down management?

Yes. It’s hard to speak specifically to how -- what the difference in the EUR will be. All we know is that we did bring on two wells early in the program without the draw down management and both of those two wells are to-date, by far our worst wells. And so what time? It does make significant difference, I would say on a per foot basis -- I am sorry. I was going to say 300 to 400 Ms per 1,000-foot. So, it makes a significant difference.

Got you. Good to hear. And my last question, just with more producing wells in the Utica and most of data point under the belt. Can you guys comment on sort of your latest Utica test results in comparison to other kind of peers, especially in the northeast of PA?

Well, I can certainly do it with -- in terms of Tioga. We don’t have a whole lot of peers in and around our WDA activity. But when you go to our Tioga or 007 track, we actually have a slide in the deck -- let’s see what page that is, on Slide 26 that shows exactly how we compare to the surrounding Utica wells.

Your next question comes from the line of Holly Stewart from Scotia Howard Weil. Go ahead please, you line is open.

John, I missed that last comment on those wells on the draw down management. Specifically what wells were you referring to? And then if you could just sort of repeat yourself on that?

We had two wells early. We’ve talked about this about a year ago maybe a little more on a pad we call E09-S that we brought those wells on too strongly. And they did not perform the same as the rest of our -- basically the rest of our inventory there.

Okay. And is there a specific rate right now that you’re getting those wells up to and holding them at?

No, it’s more just watching how much the pressure declines on a daily basis.

Okay.

It has nothing to do with the rate. Yes, it’s just press decline. We’re just minimizing that.

Yes. Okay, just wanted to clarify that. And then I apologize if I missed this as well, but can you just give a little color on how to think about that production cadence in 2019. I heard in -- I guess in your initial comments about owning an 11-well CRV pad coming online. I know there is -- maybe it’s a larger pad at 007. So I’m just trying to think about how we should model kind of the production coming in throughout 2019?

Sure. We’re going to be bringing on, in terms of bringing online wells, right now we’re scheduled to bring out about 45 wells; 21 of those will be Utica and of those Utica, four will be in 007. And then we’ll be -- the others we’ll be bringing on 24 Marcellus wells. And that will be split between the WDA and Lycoming.

Okay. And any front half versus back half weighted that we should kind of think through?

Yes. The WDA Utica has certainly weighted heavier than the front half. I think we have one other pad that comes on in the back half in the WDA that are six wells in the Utica. And then most of our WDA Marcellus wells will be in the back half. And then Lycoming and the EDA I mean -- and 007 are sort of spread evenly across the calendar year or across the fiscal year.

Okay, that’s great. And then, maybe just one last one I guess also for you John would just be on, what you’re seeing, maybe if it’s service cost deflation or escalation. What you’re seeing thus far and kind of what your expectation is in 2019?

It’s actually been fairly flat. Potentially a little bit of creep on the drill side. But I think at least on the completion side we should -- I’m hoping that we should stay relatively flat.

And there are no further questions at this time. I’ll turn the call back over to Ken Webster.

Thank you, James. 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, November 9th. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com; and to access by telephone call 1800-585-8367 and enter conference ID number 5899309. This concludes our conference call for today. Thank you and goodbye.

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