Q4 2019 Earnings Call
Thank you for standing by and welcome to the National fuel Gas Company Q4's, 29, <unk> earnings Conference call.
At this time all participants are in listen only mode. After the speakers presentation still be a question and answer session to ask a question during recession, you'll need to press star one your telephone keypad.
If you require further assistance. Please press star Zero I would now like to hand your conference over to your speaker today can websters director of Investor Relations. Please go ahead Sir.
Thank you Marcella and good morning, we appreciate you joining us on todays conference call for a discussion of last evening's earnings release with us on that.
From National fuel gas company.
Our president and Chief Executive Officer, Karen Cammy, Olo, Treasurer, and principal financial Officer.
John Mcginnis President of Seneca resources.
At the end of the prepared remarks, we will open the discussion to question.
The fourth quarter fiscal 2000.
18 earnings release in October Investor presentation, I've been posted on our Investor Relations website.
We may refer to these materials during today's call.
We would like to remind you that todays teleconference will contain forward looking statements.
While national field expectations beliefs, and projections are meeting.
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.
Lifting of certain specific risk factors with that I'll turn it over to Dave Bauer.
Thank you.
Good morning, everyone.
National people ended its fiscal year with a strong fourth quarter.
Record production at Seneca and its corresponding impact on our gathering segment offset the impact of lower realized natural gas prices contributed to a 10% increase year over year consolidated operating results.
Operationally.
We had a really good quarter across the system.
It could brought onto new pads, one each in the EDI and WD Oh.
Both has exceeded our expectations.
Cash unit costs were down meaningfully year over year, a trend we expect will continue to suffer because basin production grows.
Seneca is.
Early operating three rigs in Pennsylvania.
As I said on last quarter's call we plan to release one of those rigs once it's done drilling a six well pad in Tioga county, which should be sometime in the middle or second fiscal quarter.
I expect we'll stay that reduced level of activity for the near future.
Even at a two rig program.
You will see production growth of nearly 15% next year and single digits. The following year.
Any further activity changes will obviously be dependent on pricing.
As we move through the winter season, we'll continue to watch prices and reassess our activity level for 2021 and beyond.
So I think is operational success.
I used to directly benefit or gathering segment, which on the strength of record throughput saw revenue growth of approximately 18% over last year.
We expect future gathering throughput will grow in lockstep with senecas production, which should translate into annual revenue growth of approximately 10% on average in the near term.
Oneone hundred percent of the gathering infrastructure that supports senecas operations gives us is it a significant economic advantage.
We've attempted to highlight that in the updated IR deck, that's available on our website.
And it you'll see that we're now disclosing consolidated upstream and gathering returns for each of our major producing areas.
These returns are quite a.
Active even into two dollar netback price, we realize consolidated returns in the range of 25% to 60%.
John will get into a little more detail on this in a few minutes, but I'll point out that 60% of our forecasted 2020 production is already locked in above that level.
Two dollar and 37 that.
Jack price.
Moving to the regulated businesses today, we placed in service or line into an ACA project, which ties our supply Corporation system shells 6 billion dollar petrochemical facility in Beaver County, Pennsylvania.
As a reminder, this approximately 24 and a half million dollar investment well at about $5 million.
The annual revenues.
Construction of the Empire, North project, which has an in service date in the second half of fiscal 2020 is progressing right on schedule.
On our supply Corp. system, Yes, I'm 100 project is moving through the regulatory process without any major issues were surprises.
Once in service together these.
Two projects will add about $60 million annual pipeline and storage segment revenues.
Supply corporations rate case is proceeding according to schedule.
You'll recall, we filed that case to satisfy both the come back requirements from our previous rate settlement and the first federal income tax proceeding.
Data requests are being exchanged.
Among the parties and settlement discussions should commence by December .
We have a good history of settling for great cases, and I'm optimistic we'll do so with this case.
At the utility we continue to make investments in modernizing our distribution system.
We spent approximately $74 million on safety and reliability upgrades.
This year and expect to invest a similar amount next year.
This investment which is supported by a system modernization tracker mechanism in New York is a win win for the company in customers and that it allows us to further enhance the safety and reliability of our system, while recovering the cost to that investment on a timely basis.
In addition.
And it modernization driven rate base growth, we continue to see modest customer expansion or New York Service territory.
The improved local economic conditions in Western New York combined with continued low natural gas prices are the principal drivers of this growth.
We expect this trend will continue in the near term.
Clear sign our customers value.
He natural gas as an efficient cost effective way to heat homes, notwithstanding the state's view towards pipelines and fossil fuels.
While it's easy for policymakers to say, we ought to switch to 100% renewable energy actually doing it isn't quite as simple, especially when you consider the cost to consumers, making such a switch.
We intend to be an active participant state energy policy discussions to ensure that our 500000 plus customers in the state continue to have access to low cost reliable energy.
In closing it was good quarter in a good fiscal year for national fuel.
Looking to next year and beyond I'm confident that we can build build on our success.
Seneca had a sizable inventory of drilling locations that are highly economic even in a low gas price environment.
And pricing for next year is largely secured by hedging and marketing portfolios that reach premium markets and the Atlantic you Canadian markets.
Production from our wells will drive growth and returns not just at Seneca, but at our gathering businesses.
Well.
On top of that are regulated companies have a great backlog of expansion and modernization opportunities, which should contribute higher earnings and support the continued increase of our longstanding dividends.
In short our diversified business model makes us very well positioned to deliver value for our shareholders.
With that I'll turn the call over to John .
For an update on Sunday 'cause operations.
Thanks, Dave and good morning, everyone.
Seneca had a strong fourth quarter, we produced 59.1 Bcf feet, an increase of around 25% compared to last year's fourth quarter total annual net production came in towards the high end of our guidance at 211.8.
Bcf feet again, a new high for Seneca and around a 19% increase year over year.
As a fiscal 19, we have now produced over at Tcf of gas from our shelf acreage in Pennsylvania.
For the year capital expenditures and expenses on a per unit basis, we're all within our guidance ranges.
Yes.
Reserves increased by almost 600 bcf fee or 23% to 3.1 Tcf fee.
Proved developed reserves now make up approximately 67% our total reserves.
We continue to reduce our through your average on F. In D. costs now at 56 cents per Mcf fee.
We have posted a we have posted an updated Marcellus and Utica type curves for all of our production areas in our Q4 investor deck, including an updated Debbie D.A. Utica development type curve on page 20.
As a reminder, our initial Utica type curve was based on our first five appraisal wells on the CRB area.
Our updated.
Development type curve is based on results to date for all 26 wells online in this area.
This type curve ranges between 1.6 to 1.7 Bcf per thousand foot and assumes all wells going forward or bounded and space around 1200 feet apart.
Our latest Utica pad located to the south eastern.
Rich Valley has now been online for over three months.
Four out of the five wells on this path are performing above our type curves and on a per well average is our best to date and the WD.
Including this pad, we're now producing from 11 wells along the southern boundary of the CRB area, what kind of these wells producing.
Above our updated type curve.
This trend continues as we move to the south from the CRB area across our acreage position towards Boon Mountain, we may introduce a second Utica type curve and a better portray the positive results were seeing along this corridor.
We need to bring online additional pads in this area. However, before we're comfortable.
Adding that second curve.
With respect to our Debbie D.A. Utica drilling completion design, we have not seen much difference in terms of production between the lower Utica versus the upper point Pleasant.
Of the 26 CRB wells brought online to date or best performers utilized drawdown management and were completed with that produce fluid.
End of less than 95%.
We will continue to employ a conservative drawdown management plan to reduce issues related to proppant embedment crushing.
And we'll take an active approach to ensure consistent fluid blend percentages across stages for each well.
In terms of completion intensity the larger.
Designs utilizing higher proppant loading and tighter stage spacing tighter stage spacing have resulted in higher production on a per well basis.
But as a bit too early determine if that translates into improved economics.
In California, we produced 610000 barrels of oil during the fourth quarter an increase of.
Around 6% over the third quarter.
This increase was due primarily to our recent drilling activity a pioneer located near South Midway Sunset field.
Brought online 13, new producers in July and August and these wells averaged around 500 barrels per day up net production during the fourth quarter.
And finally or 17 and section.
Located near our North Midway Sunset field continues to produce just over 400 net barrels per day.
Moving to our fiscal 20 guidance, our capital expenditures and production range remained the same.
Production growth forecasted to be up around 13% at the midpoint year over year should occur primarily.
In the second fourth quarters, as we bring on new pads.
Moderate decline during both the first and third quarters.
In September when Nymex prices rallied we were successful in adding another 20% layer of fiscal 20 hedges at an average price of $2.54.
As a result, we now have.
Locked up around 136 Bcf around 60% of our fiscal 20 East Division gas production physically and financially at a realized price of $2.30 per Mcf.
We have another 60 Bcf a firm sales providing basis protection, so over 87% of our forecasted gas production.
And is already sold.
We currently estimate that we'll have around 28 bcf of gas exposed to the spot market. So these volumes are potentially at risk for curtailment.
Already in October we experienced several days at very low in basin prices and we elected to shut downs bioproduction totaling just over half a bcf.
Finally in California around 70% of our oil production is hedged at an average price of just over $61 per barrel.
And with that I'll turn it over to Karen.
Thank you John and good morning, everyone last night National fuel reported fourth quarter, adjusted operating results and 54 cents per share.
An increase of five cents or 10% over last year.
The majority that earnings growth was driven by our nonregulated operations, where the 12 Bcf the year over year increase in senecas production and the associated gathering throughput more than offset lower realized natural gas prices.
Like any quarter.
We're a number of smaller moving pieces, but the earnings release does a good job describing those drivers.
One item worth noting is our effective tax rate for the corridor, which came in at 19.4% which was below our expectations.
The fourth quarter can see some movement year over year on our effective rate as we true.
Some annual accounting estimates this year was no different.
Well I'm a subjective taxes as a reminder, the enhanced oil recovery credit stays down at the end of fiscal 2019 and as a result, our effective tax rate is expected to increase to approximately 25% for fiscal 2020.
Looking to next year, we are revising our fiscal 2020 earnings guidance down to a range of $3 to $3 on 30 cents per share. This is principally driven by three main factors.
First we are reducing our natural gas price assumption to $2.40 per annum Beachy you down 15 cents for my.
Preliminary guidance.
This drop was partially offset by the incremental hedges that we added during the quarter.
Well our price deck is generally in line with the future Strep reference every 10 cents change in IMAX is approximately five cents in earnings per share for the year.
We are also revising our expected.
Waste onsite oil price premium.
From 108% to 106% up W.G.I. based on recent realizations in California.
The second main item relates to an expected increase in operating expenses, mainly related to non cash pension and postretirement benefit expenses.
Since our last.
Earnings call interest rates fell, meaning Lee such that our final actuarial assumptions reflected lower discount rates and a reduction in the forward looking asset return assumptions than was previously forecasted.
As a result, we're now expecting pipeline and storage a win and non surface pension cost to collectively.
Increased 45% from fiscal year 19 levels well similar costs in the utility are expected to collectively increased approximately 3%.
With regards to the increases related to the pipeline and storage benefit costs as Dave mentioned, we're currently in a rate case with supply where we expect to.
Burn rates the funding at these benefits plans.
Well that's main driver of earnings guidance decreases related to Senecas, DNA rate, which is up two and half sense at the mid Pike point from last quarter's preliminary guidance.
This is principally driven by an increase in our full cost pool, plugging and abandonment liability in California.
There were part of an ongoing state wide effort to reduce the number of outstanding idle wells at a faster pace than before and using more stringent plugging requirements mandated by the state.
On top of these incremental requirements service costs for plugging crews are increasing due to the demand to meet the state wide initiative.
As a result of this assumed increase in plugging and abandonment costs per well our asset retirement liability has increased meaningfully.
In addition to driving our DNA rate higher we also will see higher ongoing accretion expense during the year.
Other than the items I just mentioned on some minor revisions to our E N P.
He unit cost.
The rest of our guidance remains unchanged.
One item I wanted to clarify from my previous guidance, we expect property taxes in our pipeline and storage segment to increase approximately $2 million in fiscal 2020 relative to the 2019 bottles.
This is primarily a result.
The schedule scheduled phase out of a multiyear tax incentive negotiated with certain jurisdictions when the Empire connector project, what's constructed in 2008.
Over the coming years, we'd expect further phase outs in other jurisdictions driving additional property tax increases in the segment.
With respect to capital spending our fiscal 2020 guidance remains the same at $725 million to $820 million at the midpoint. This represents a slight decrease from our fiscal 2019 spending.
From a financing perspective, we ended the fiscal year with a modest amount of short term.
Greetings outstanding.
As we look into fiscal 2020 with the ongoing construction of the and player in North project, along with our other financing requirements, we expect our full year incremental.
Our earnings should be around $200 million for the year.
With this in mind, we now forecast interest expense to be in the range.
Range of $105 million to $110 million.
We have ample liquidity under our $750 million credit facility and that will be our primary Avenue to fund this outspend.
Our next long term maturity is still two years out. So we don't have a pressing need to be active in the capital markets.
That being said.
We always remain opportunistic and with the steep drop in interest rates, we continue to evaluate all other options.
In conclusion, we are in a good spot financially we have significant liquidity are investment grade credit rating has a stable outlook and we have no near term debt maturities. This along with a strong hedge book puts us on.
It's putting to navigate a challenging commodity price environment.
With that we can turn the call over to the operator for questions.
At this time I'd like to remind everyone in order to ask a question. Please press star and the number one on your telephone keypad.
Your first question comes from line of Holly Stewart from Scotia Howard.
Howard well your line is open.
Good morning.
I only.
Maybe the first one just high level, either diever or John just kind of thinking about the comments around I'm, having the flexibility to reduce capital spending to Seneca on pricing.
A related.
Pricing if need be just can you give a little plus a little color around.
Around that comment I guess, given you know the hedge book deal. You know is it's a multi year look out like how do you think about the weakness in pricing and and your reaction to that.
Yeah. Thanks.
Our current plan is to drop rigs during the fiscal second quarter, obviously, that's being driven to reduce our spot exposure at the current screw up that rig is currently drilling Utica wells in Tioga, a week and as we move into the winter season here, we're going to continue to watch and sale prices go I of course.
Our success, one layering in additional firm sales.
Then that may postponed.
The the chance or the potential drop in that second rig, but at this stage I think we'll just wait to get to the winter season, and then reevaluate at that point, whether or not and make some stuff to drop.
Other rug.
Okay, Okay, and then and you know maybe a follow on to it to that John would be do you have a level of you know spending I guess that you would think about is kind of maintenance capital and then is there you know analysis eat it rig count are well count that yeah that we would think about.
<unk>, then to kind of hold production flat.
Yeah for us to hold production flat, we've calculated it looked at this before it's between a one to two rig case, a spend about $250 million to $300 million a year or so at one rig I don't think we'd be able to hold it flat, but certainly if if we're back and forth between one to.
One to two rigs we can do that.
Okay. That's done that that's super helpful. And then maybe just John any incremental color you could provide on the.
The CRV you'd okay. You are that it looked like it modestly went down even though the the laterals.
Appeared to have increase.
Yes modestly went down on a per foot basis, but but honestly, we expected that our first five wells were unbounded appraisal wells now we're drilling a each pad that we go to we're drilling multiple development wells at our spacing is about 1200 foot. So we expected to see a little bit of a decrease now that all of these.
Well as our bounded so it really wasn't that big of a surprise to have a slight deduction.
That's great. Thanks.
Yep.
Your next question comes from line have Kim Winter from Gabelli. Your line is open.
Good morning, Thanks for taking my question Ive I'm sort of a big.
Picture strategic question that follows up on that first one so the utility at a nice year 70 cents a share earnings and if you look small gas utilities trade 25 times earnings, which gets you about 18 Bucks pipeline and storage gathering earned a buck 52, if a if you.
Conservative really put a 15 months going that you're at about 23 Bucks So summed up here at $41.
And with NFC, a 44 seems like you're not getting.
Full value or much value at all for Seneca, but to capital budget.
800 million has about 60%.
And allocated to Seneca I'm just wondering if you guys are considered buying more regulated assets like maybe even into the you know electric or water distribution business.
Yes, Hi, Tim.
Our focus in the near term is on on our natural gas opportunities.
And that's that's across to the value chain right. So we've got the opportunity to two to grow the the pipeline business in a meaningful way and the you to the our existing utility in a it all caught more of a modest way the the returns on the the wells that were drilling.
As I said in my.
Marks are are quite good when you look at it on a consolidated basis.
So we feel good about our program you know when we think longer term and bigger picture about.
How about other directions, we might take I mean, certainly acquiring other regulated assets, whether they'd be electric water for gas or are certainly.
Avenues that we could pursue amongst many different ones you know as with anything we've got to compare a return potential for for what we buy with what we already have and these are things that we we returned routinely evaluate and ER and discussed with the board.
Okay, great. Thank you.
<unk>.
Your next question comes from line of Gordon Lloyd from Raymond James Your line is open.
Hi, good morning, Thanks for taking my question.
You bet.
Yes, So I was just looking at them.
But the slide 58, 10, or where do you guys give all the.
The Seneca.
Can I mean.
And I recall in the last.
And this time last quarter, we're having the call that.
Good two rigs, but every meeting will be located in the WD.
Trying to reconcile just trying to figure out.
And if there's any other factors, but you guys had in terms of.
Susan.
And to allocate the remaining rig in the joint program going for it to the W. Instead of to the JV.
Yes sure.
Honestly a rig in the E.D.A. with continued activity there would generate volumes would have to be sold in the spot market and if the spot market prices are poor.
Obviously that just wouldn't make a whole lot of subs.
Our spot pricing at our refreshed as our receipt point in the WD has historically ranged between sense 10 cents to 30 cents better than we see it the EPA sales points at TGP zone, four and also in lighty ER and almost all of our activity in the Debbie da is.
Because currently unreturned trips to existing pads with existing infrastructure, but significantly enhances our consolidated economics.
We also view a two rig program there will allow us to grow into RFM 100, ladies south commitment, which is currently scheduled to come online late in 2021. So that's really the driver of why we have.
The two rigs from the W. da.
Okay, that's extremely helpful and but I guess my one follow up and just kind of a simple clarification question.
The a return metrics located on slide 15. They all include factoring in the enterprise for the.
Right.
Absolutely yes.
And that's all I had been thanks for taking my question.
Your next question comes from one of Chris Santa Fe. Your line is open.
Hey, good morning, everyone.
Hey, Chris Hey, I appreciate all the calling this morning as always I think I've a question.
And for each of you said, Karen I guess this or appreciate the color on the drivers of earnings tax impacts in Fourq, you and the change from 19 to 20.
I'm curious if you have an anticipated cash tax rate you could share I think the initial expectation in a while ago was.
For modest refunds in fiscal 1920, given some 18.
I am usage credit usage, but I don't know with the passage of time and updates to your plan. If that's still a good base assumption.
Yes, so, whereas we're still in that position.
Okay. I guess I guess, you had said net financing you thought would be 200, so I guess I get it back into what that implies.
But it was implying a positive number for me so I just want to confirm that yep.
Okay, that's I'm sorry.
Okay. Thanks for that.
Then John if I could switch and follow up on just the last.
Question or to better understand the calculation that you've embedded in those consolidated I ours for Seneca, including gathering.
You know in the footnotes there that gathering Capex included is for expected remaining return trip locations.
Yes.
I haven't impression and what that means but I think safer just to ask you went I mean, what does that mean.
Well I guess going again muted versus what is included.
Versus excluded in regard to gathering Capex, it's all in there Chris It's all included.
Okay.
I think as well so I guess going all the gathering is included in those economics.
On our return trip, so actually for all of it.
Okay.
So this does I guess the sunk cost if you're going to reuse.
During infrastructure that was predicated for the Marcellus development originally.
And it gets reuse to recycle for Utica development now.
I guess is that you did this on cost and therefore not applicable in the calculation because it's looking forward or.
To use do you carve it up and Sheraton, though.
Yes, no we look at it on a point forward basis.
Okay understood that's how I just want to make sure okay.
And then finally I guess, Dave for you you know Theres heighten media focus on utilities and the environment I mean, if we look at what's going on with PGT in California.
And and the drama between National grid, and the PSC and Governor Cuomo here in New York.
I'm just curious you know with this C.L.C.P.A. asked earlier this year.
What things NFG can do work is doing to prepare for the impacts that recognizing of course, the targeted goals are some years future.
Yeah.
Sure what we're really in the the early stages. So it's a it's a little early to say what the exact impact is gonna be there's a process that's going to play out over a few years. The first step is is the appointment of a climate action Council by January of next year and.
After that there's four years of.
Have a process to get any sort of regulation in place, we intend to to be an active participant Donna careless, who you know is a is the president of our utility was a was appointed to the the climate action.
Council, which is the main committee that will be the overseeing the process. So we'll have a seat at the table and are able to keep everyone.
Up to speed as a as we move through time, you know, but I think I think long run you know, there's definitely going to be a role for a for and LDC in our.
Or service territory.
You just consider a few facts like the that we serve 95% of the the heating load of a of the customers and our or service territory or reliabilities better than 99.99%.
For Cold climate, you know better than.
The 5% of the days are have temperatures below 30 degrees and and heating with electricity is pretty expensive.
As much as four times as expensive as is with natural gas and our service territory. So when you overlay. This for that were not necessarily a rich community. The median income in the city of outflows less than 40000.
$1, Yeah, I think it's pretty hard to see.
LDC going away, if cost and reliability, our or factors that ultimately.
And are the equation.
And that's that's part of the climate action committees mandate is to consider.
Those items as well I mean, it's my hope, but I'm not I'm asking.
Yeah as I understand the cost benefit is or is it definitely factor.
Okay, and then I mean, you got to understand Chris that this this was you know if you read the legislation. It basically sets targets and then says we're going to they're going to set up committees to figure out how we're going to reach those targets. There is not right know that [laughter].
That is what I.
So it just and it feels like having read a governor foremost letter to see about.
The the supply shortage, you know that national grid is talking about I mean, it just it feels like utilities, saying, we wouldn't have this problem, if you unapproved pipeline and pick.
You're saying.
You have a problem you didnt planned for and it's your fault and so I guess when you. When you contrast that werent or compare that against legislation that has defined goals that no defined path I.
I, just worry about anybody getting getting caught up in that.
That's what sort of probably unfortunately, I sorry I saw.
Lease you guys put out a couple of days ago about.
Niagara Falls from zero net energy home once you had.
Role to plan and I'm, just curious like things like that are they scalable and is that how.
And it energy distribution sort of fits into the pie.
Yeah, I mean, those are all things that were.
That we're exploring and again I think the when you consider the reliability. So when you consider the cost savings from from natural gas. It's it's really hard to see how how electrification of heating loads in Western New York makes sense for the consumer.
Okay, all right well, thanks, that's left because when I appreciate it.
Talking about.
Again, it's just a question please press star and the number one on your telephone at your next question comes from line has someone from GE Research. Your line is open.
Hi, Good morning, Thanks for taking my question Martin I'm, So I'm kneeling following the Appalachian MP named in close your company.
Can you walk need to the economics of a well Ah first how much of caustic drill and complete it and then secondly, a using D.
That got Nat gas prices at the current strip, what do we turn up the well just allow excluding the gathering system.
Yep.
If you go to our slide duck.
Page 58.
All of that information is on there and it's as far as a Seneca Standalone. Our economics are on the footnote on that exact same slide so it'll go through the costs the average costs across each of our producing areas I'll give you an average.
You are for thousand foot and it also show you our economics, both on a standalone and also on a consolidated basis.
Okay. I mean since you can you provide capex on the foot thousand foot, what's the average, but what's the average but for a while sorry. If you also look at that slide gives you the.
Completed lateral length for each of those producing areas.
Oh I see okay, I see it now okay great.
That's my follow up.
You talked much about dropping one week next year due to loss Caf low gas prices I think you touched on this a with Holly earlier I just want make sure I understand.
And it.
It's a lot of drilling that youd.
Do you own that and not on land held by production. How do you think about trading off between drilling at current prices and holding off and when you for higher gas prices.
Well, we're pretty well hedged going into next year or commit.
Okay, where in this year, where our right where at 60% had we've already sold 87% of our gas and as I said with with Holly's question as we go through the winter season.
Well to keep an eye on prices, especially strip prices over the next year or two and at that point will decide it does it make sense to continue with the tour in case or is it time.
To make a change.
Okay, and then if I could sneak one more question that I just want to clarify this.
The unit cash cost at dollar 25 per Mcf E.
Is that the all the all your all in cash operating cost at the wellhead.
Yes.
Okay and then since.
All of every coffee seemed to define cost differently.
The cash cost differently, you mentioned LNG transportation did I didn't costs include SG in a financing in Texas.
Yes, it does.
Okay, great. Thank you.
Hi, Thank you.
There are no other questions at this time I'll turn the call. So for Q1 0, Webster for closing remarks.
Thank you Marcella, 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 three PM eastern time on both our website.
And my telephone and will run through the close of business on Friday November Eightth.
To access the replay on line. Please visit our Investor Relations Web site at Investor Dot National fuel gas dot com and to access by telephone call. One 805 eight.
Five athree six seven and enter conference I'd number 4581569.
This concludes our conference call for today, Thank you and goodbye.