Q4 2020 National Fuel Gas Co Earnings Call
And.
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Ladies and gentlemen, thank you for standing by and welcome to the Q4 2020 National fuel gas Company earnings Conference call.
At this time all participants are in a listen all the mode. After the speakers presentation, there will be a question and answer session.
I'll ask a question during the session you will need to press star one on your telephone. Please be advised that todays conference is being recorded if you require any further assistance. Please press star Zero I would you like hand, the conference over to your speaker today, Ken but curious director Investor Relations. Thank you. Please go ahead.
Thank you, Mike 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 de Bower, President and Chief Executive Officer, Jerry Cambiasso, 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 2020 earnings release in November Investor presentation have been posted on our Investor Relations website we.
We may refer to these materials during todays call.
We would like to remind you that today's teleconference will contain forward looking statements.
While national fuel 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 bank of America Global Energy Conference next week. Please contact me or the conference planners to schedule a meeting with the management team.
With that I'll turn it over to Dave Bauer.
Thank you Ken good morning, everyone.
As we reported last nights release National fuels fourth quarter operating results were 40 cents per share.
Assistant with the earlier quarters lower commodity prices were the main driver contributing to the 14 cents per share drop in operating results and for sure in the non cash ceiling test impairment charge.
Despite the drop in earnings the quarter went as planned with operating results right in line with our expectations.
Fiscal 2020 was a remarkable year for national fuel.
Against the backdrop of a pandemic, we completed a highly accretive Appalachian acquisition and brought online a significant pipeline expansion project, all while continuing to safely and reliably operate our businesses across the natural gas value chain.
Looking ahead the outlook for natural gas has improved significantly and national fuel's, well positioned for meaningful earnings and cash flow growth.
We continue to see success with our expansion projects at our FERC regulated pipeline businesses.
We placed our Empire North project in service on September 15th.
As a reminder, this project is fully contracted with the bulk of the commitments extending for 15 years.
The project is expected to add about $27 million in annual revenues.
It looks like the final capital cost will come in around $129 million, which is more than 10% below our initial cost estimates.
Constructing in placing this project into service safely on schedule and under budget in the midst of a pandemic was quite an accomplishment. Thank.
Thank you to all our employees and contractors for the exceptional effort it took to complete it.
We continue to make progress on our EPS I'm 100 project and Transcos Companion Lighty South expansion is also on track.
As a reminder, all of the facilities for both projects are in Pennsylvania.
There were a few permits still outstanding and we expect to receive them. This winter.
We have started to order longer lead time items and once we receive the remaining permits we'll file for our notice to proceed.
All of this keeps us on pace to be in service near the end of calendar 2021.
And again as a reminder, FM 100 will add approximately $50 million in annual revenues between $35 million expansion component and the additional $15 million modernization rate step up agreed to in our February rate case settlement.
Moving to our upstream and gathering operations, we closed the acquisition of shells Appalachian assets back in July and now have a few months of operations under our belt.
The transition cannot have gone more smoothly and were very excited about the long term benefits of this acquisition.
It added significant scale lowered our per unit cost structure and added hundreds of highly economic development locations and tail with county, which are supported by company on gathering systems and valuable firm transportation, including on National Fuel's Empire pipeline.
In addition production and reserves continue to be in line with our initial expectations and as we spend more time operating the assets, we're finding additional efficiencies and revenue enhancement opportunities.
Seneca is currently operating a single rig moves between our eastern and Western development area.
On last quarter's call, we discussed the possibility of adding a second rig prior to the start date of lifestyle.
Given both the meaningful improvement in natural gas prices for fiscal 2002, and our expectations on the timing of the FM 100, Mighty South projects, we've decided to move up the rig add to January.
This will allow us to lineup first production with the in service date Seneca is new capacity.
It will also allow us to capture the benefits higher winter pricing.
As you can see from last nights release, we've already hedged the fiscal 22 production expected from the wells that will be drilled by the second rate.
Because we won't see production from these wells until late in calendar 2021, Theres no impact to our fiscal 21 production or earnings guidance.
Nevertheless, in spite of the incremental $60 million in capital associated with this rate, we still expect to generate in excess of $100 million of free cash flow from our upstream and gathering businesses.
While this increase in activity level differs from the approach taken by many of our peers, but.
The strength of our balance sheet, our methodical approach to hedging and our significant depth of high quality inventory allows us to take this step to accelerate value, while still generating significant free cash flow.
Over time, the second rig is expected to focus principally in our eastern development area, where we have some of the most economic development opportunities and Appalachian.
If you recall, our valuation of the Tioga County acquisition was based solely on Pdps and the related gathering assets, we did not attribute any value to the highly economic undeveloped locations.
By adding a rig we are now able to pull forward. The development of these properties further enhancing the value of the assets, including growing throughput on our gathering facilities.
Our utility business continues to run smoothly in spite of the pandemic.
Our team has done a terrific job adapting to the new reality.
Because of the economic backdrop in our service territory, we've seen a drop in large volume commercial and industrial throughput.
But thanks to our rate tracking mechanisms in New York the impact to margin has been manageable.
In spite of the pandemic, we had a very successful construction season.
Replacing over 150 miles of older pipe on the system.
More than two thirds of the spending associated with the program will be captured in our system modernization tracking mechanism.
Taking all this together our outlook for earnings and cash flow growth as strong as.
As a result of the improved outlook for natural gas prices were revising our earnings guidance up to $3.70 at the midpoint, an increase of more than 25% over our fiscal 2020 the results.
Despite the backwardation in the natural gas curve.
As we look to fiscal 2002, the increased activity at Seneca combined with the expected in service date of the EPS from 100 project and the continued modest growth in our utility segment are all expected to drive further earnings growth.
Switching gears in September we published our initial corporate responsibility report.
This was an important step in furthering our SG disclosures and highlighting our ongoing initiatives are continuing the course, we've been on for a number of years.
Over the past two decades, we've made significant investments to modernize our natural gas distribution transportation and storage facilities.
This is significantly reduced emissions across our system.
For example, relative to 1990 levels, our utilities EPA subpar w. emissions are down by over 60%.
We recognize the importance of reducing the global carbon footprint and we continue to find ways to further reduce our own emissions profile as we grow our business.
This is perhaps most evident on the Empire North project, where we installed our first electric motor drive compressor station, which virtually eliminates combustion emissions from those operations.
We also look for also continue to look for ways to incorporate renewable natural gas into our transportation and distribution systems.
This past year, we believe our systems first interconnect with an anaerobic digester facility.
All of these initiatives highlight on natural gas will continue to be part of the long term energy solution.
In closing I am excited about the future for national fuel.
2020 was a year of challenges, but also one of opportunity.
We've taken several critical steps that have strengthened the company and position it for near term growth.
When we look to fiscal 2002 and beyond we expect to generate consistent meaningful cash flow at current strip pricing.
This should more than cover our growing dividend and further improve our already strong balance sheet, giving us the flexibility to pursue additional growth opportunities as they arise.
With that I will turn it over to John for an update on our upstream operations.
Thanks, Dave and good morning, everyone.
Seneca had a strong fourth quarter, we produced 67.3 Bcf fee increase of around 14% compared to last years fourth quarter.
Despite low end basin natural gas prices, which led us to voluntarily curtail about six Bcf, we achieved our largest quarterly production ever.
For the year, we curtailed 17 Bcf and annual net production came in just over 241 Bcf.
This new fiscal year high for Seneca the supported by our development program and the impact of our recent acquisition.
For the year capital expenditures, excluding the acquisition ended up at around $384 million, a reduction of approximately a $108 million or 22% from the prior year.
Expenses on a per unit basis were down 8% from last year and were all within our fiscal 2020 guidance ranges.
Ceded reserves increased by 359 Bcf fee or 12% to just under three and a half tcf.
With the increase largely driven by our acquisition during the fourth quarter.
Proved developed reserves now make up approximately 84% of total reserves.
As we discussed last quarter, we have updated our Marcellus and Utica development type curves and consolidated economics by producing area and these are included in our Q4 investor present presentation.
As a result of our recent acquisition, we now have substantial inventory of both Utica and Marcellus drilling locations in Tioga and our inventory has expanded to approximately 300 locations into India.
Moving to the W. DNA, our near term development is expected to shift towards the Rich Valley Beechwood development area, which is located immediately to the south of our CRB area, but we are focused over the past few years.
In the originality Beechwood area, we have around 100, Utica drilling locations and we'll be able to utilize our existing gathering trunk line.
Based on results to date, we believe the economics will be superior to those related to our WD a Utica return trips as shown on slide 25, our of our Investor presentation. We have five pads with 19 wells currently producing in this area. These pads are performing at or above our previously posted Utica type.
Sure.
In California, we produced around 555000 barrels of oil during the fourth quarter, a decrease of around 9% from last years fourth quarter.
Year over year oil production was largely flat with a slight increase of 26000 barrels.
Earlier this year in order to cut costs as a result of low oil prices, we significantly reduced well work and steam volumes across most of our heavy oil fields.
This modestly impacted our production decline rates in these fields during our third and fourth quarters. However, we have recently increased steam volumes to previous levels in some of these fields and we will continue to permit new wells to allow for a return to drilling in the event oil prices improve.
As we are currently planning to differ much of our fiscal 21 development program in California, We have budgeted only 10 million in capex, but again that prices rebound our intention is to increase our activity in California to return to our development programs and midway Sunset and Coalinga.
So moving to our fiscal 21 guidance as Dave mentioned earlier in connection with the continued development of the lighting sales and EPS on 100 projects and a deep inventory of highly economic Utica development locations in Tioga as a result of our recent acquisition, we intend to add a second rig early in 2021.
This additional rig will focus on our EA assets in both like coming in Tioga and longer term, we would expect relatively balanced activity between the EPA and the W. da.
As part of our recent acquisition, we secured 100 million a day and Dominion, but access to Transco Leidy line and the Lady South project, providing us with Optionality to utilize this capacity from Tioga. In addition to Lycoming and the W. da.
First production from the additional rig is expected in early fiscal 2022 to align with the expected lighty, South and service date, allowing Seneca to utilize this 330 million a day of incremental pipeline capacity to reach premium markets during the winter heating season.
As a result of adding the second rig for approximately nine months of the fiscal year, we are increasing our fiscal 21 capex by around $60 million from their previous guidance to a total of $370 million at the midpoint even.
Even with the second rig we are forecasting a decrease in capital expenditures of around $15 million year over year.
Most of our production growth in fiscal 21 forecasted to be up over 30% at the midpoint should occur during the first half of the year with a moderate decline during the back half as we defer completion and flowback activity until the winter season, when our new capacity is targeted to be in service.
Moving forward, we have 234 Bcf around 77% of our fiscal 21 East Division gas production locked in physically and financially we have another 41 bcf of firm sales providing basis protection, so 90% around 90% of our forecasted gas production is already sold.
We currently estimate that we'll have around 30 bcf of gas exposed to the spot market. So as always these volumes are potentially at risk for comments.
And finally in California around 50% of our oil production is hedged at an average price of just over $58 per barrel.
With that I'll turn it over to Karen.
Thank you John and good morning, everyone as Dave stated at the beginning of the Cob National field operating results for the quarter came in at 40 cents per share adjusting for items impacting comparability, which was in line with our expectations.
Although our upstream business continued to pay significant commodity price headwinds each of our businesses performed well during the quarter setting the company up for a strong fiscal 2021.
One item of note during the fourth quarter was our effective tax rate, which had approximately 15% with much lower than expectations and the prior year.
Periodic rate, we're required to assess the appropriate tax rate to use for recording deferred tax assets and liabilities.
Our recently closed acquisition included significant additional firm transportation capacity to markets outside of Pennsylvania, which resulted in the forecasted percentage of total revenue applicable to Pennsylvania to be lower in the future.
As a result, we were required to remeasure the deferred taxes on our balance sheet to reflect the lower expected state tax rate. Since we are in a net liability position. We recorded the difference that the benefit to deferred income tax expense, reducing our effective tax rate for the quarter.
Let's turn to fiscal 21, we've revised our earnings guidance higher to a range of $3.55 to $3.85 per share our 3070 cents at the midpoint.
There are a couple of major drivers behind that increase.
First we increased our Nymex assumption to $3 per MB to you and correspondingly increased our in basin pricing forecast to $2.50 in the winter months and $2.10 in the summer and shoulder months.
Second as a result of the ceiling test impairment charge recorded during the quarter. We now expect BDNA at Seneca to be in the range of 60 to 65 cents per Mcf.
This does not include any future impairments at Seneca.
Going the other direction, reflecting recent changes and forward crude oil prices, we've reduced our W.T.I. assumption to $37.50 per barrel and made a slight adjustment to our California basis differential moving it down from 95% to 94% as a result of recent trends.
As we are experiencing in the region.
Additionally, while the increase in natural gas prices as a significant benefit to earnings there are few natural offsets to that.
First in Pennsylvania, we are subject to the state impact fee Michelle.
This shows up in our other taxes line item on the income statement and is calculated based upon the age of each well and the average Nymex gas price for the year.
There is a tipping point into a higher tier as we hit the $3 per NBT you Mark.
Our updated forecast reflects increased fee, which is approximately $3 million higher for the fiscal year.
Additionally, as John mentioned, we're forecasting a return to normal steam volumes in California, one of the key inputs and our steam generation is natural gas and with the increase in pricing, we expect modest bring higher LLC in the region, which is reflected in the slight widening of our guidance range now forecasts.
Between 83, and 86 cents per Mcf.
Overall these adjustments on the cost side are more than offset by the benefit of expire expected higher realizations on our natural gas production.
Further and forgot production as John mentioned, we continue to actively hedge as the forward curve moves up and now have price protection and 77% of our natural gas volumes. We also have 50% of our crude oil production hedged at $58 per barrel.
Moving to the regulated businesses as a reminder, we are forecasting a return to normal weather at the utility, which will drive a 5 million dollar increase in margin year over year.
Combining this with $3 million of incremental revenue related to our new ERP system modernization tracker, we expect to see margin growth of approximately 2% for the year.
Going in the opposite direction.
We now project, our Nam to increase approximately 3% to 4%, which is modestly higher than our previous guidance.
As a result, we now expect operating income to be relatively flat year over year.
At our pipeline and storage business, our assumptions remain unchanged for the year.
We still expect revenues to be in the range of $330 million to $340 million and on an expense to increase approximately 4% for the year.
Turning to capital on a consolidated basis, we are in line with our expectations for fiscal 20.
Looking to this year as Dave and Dan Both mentioned, we expect Senecas capital to increase by approximately $60 million as a result of the increased Appalachian activity level.
All of our other guidance ranges remain unchanged so at the midpoint of our range.
We expect spending to be $775 million.
Tying everything together, we now forecast our funds from operations to exceed capital spending by $50 million to $75 million on a consolidated basis. This is a great outcome when considering our expectation that we will be constructing a large portion of the FM 100 project in fiscal 21.
Which is the most capital intensive pipeline project in the company's history.
Combining this free cash flow with the proceeds from our timber sale, which we expect to close next month, we don't expect any external financing needs absent seasonal working capital changes.
With that I'll close and ask the operator to open the line for questions.
At this time I would like to remind everyone in order to ask a question you will need to press star one on your telephone.
To withdraw your question press, the pound or hash key please standby will be compiled acuity roster.
Our first question comes from Holly Stewart from Scotia Capital. Please go ahead.
Good morning, Gary Gary.
Morning.
Maybe a first for John.
John I think we've always sort of thought of the maintenance level being like a rig and a half for Seneca understanding right now there is a higher level of DUC inventory.
With your larger production base with the shell acquisition now being closed has that moved sharp assumptions moves higher and then sort of breaking that should we think about that two rig in 2010, keeping production flat or would you expect some growth with that activity.
Holly good morning too.
Thats exactly right, we really haven't changed our maintenance at one and a half as a result of the show acquisition.
It's still pretty much remains in that in that bracket, I'd say, one and a half to two.
At a two rig pace youre look in that.
It was consistently two rigs were looking at anywhere from.
Side, 9% growth on an annual basis, depending on where those rigs are active.
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The maintenance capital May change, a little bit warrants lighty south is online.
Right now it's on we're still at that one and a half to two red pace.
Okay. Okay.
Thats good color, maybe it sounded like from Williams conference call. The lights out at least part of that project was coming on a little bit early is any of that.
Capacity going to be allocated to syndicate.
Our goal is to is we're targeting the winter the winter heating season.
If it's on early and we have to sit down with winners and really understand how that's going to play.
Play out, but our target right now is to make sure that we have the production to fill lighty cells as winter comes on next winter.
Okay. Okay.
At maybe.
Another one for me.
The second rig that we're talking about is that under a long term contract or how should we think about that is if if prices start to pull back in a meaningful way here, yes, it will be a one year contract.
So.
It does yes prices decline and we'll certainly be able to pull a rig up the table.
Okay, and then maybe just one final one for me if I could get them.
On our it looks like.
As of yesterday that the cash market remains very weak in the basin.
Any any.
Any production currently shutting today Phil.
Yes, actually October our spot volumes were pretty much entirely shut in.
And you're right November has started the same way as spot volumes remain curtailed in Appalachia.
At least what that will assist back to us we are voluntarily curtailing production.
Okay. That's helpful. Thank.
Thank you.
Your next question comes from Brian singer from Goldman Sachs.
Thank you good morning.
Alright, okay.
Oh up on Ali's question for Dave the upstream.
You talked about how the updated economics and type curves.
Curves.
Cross the portfolio impacts your thought process on where it was in eastern and Western development area. As you place your rigs and then as you bring on this second rig next year.
How long does that stay in in the East you mentioned I think it's initially in eastern just wondered if you could add any color there.
Yes, absolutely.
Yes.
Let's start with the second part first yes, it will pretty much remained in the east every once in a while it will it may drill a single pad or a few wells in the in the west, but but largely 90% plus of its time will be in the EPA.
And certainly we recognize that our highest returns are in the EPA, both in Tioga and Lycoming.
But having said that our our capital allocation on an annual basis has really been predicated on our firm transportation portfolio.
We're just not going to grow our production base, just a producing to the local market.
So at the end of the day, our capital allocation is really geared towards ensuring that we fill our for ft commitments and get our gas into the right markets.
Great. Thank you and then my follow up I think at the end of add Dave Bauer opening comments you made the point that.
Especially when you look out into 2022, there's more free cash flow and balance sheet flexibility to consider additional growth opportunities. If they arise I just wondered whether you see those opportunities more organically versus inorganically and upstream oversees the upstream versus midstream.
Yes, well, we certainly have.
A very large acreage position that we could develop organically.
But having said that we are.
Well and I should add to that that we've got a great track record of sort of expanding our our Interstate pipeline network, but we are always mindful of.
We have other opportunities to.
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That.
That may come around so I guess, that's a long way of saying that that I think we've got the ability to grow organically, but then also have the flexibility to to make strategic acquisitions its.
If they come about makes sense.
Great. Thank you.
Yep.
Your next question comes from Sutton from Bank of America.
Thanks, Good morning.
Thank you for the Capex guidance for fiscal 2021 wondering if.
If you could get Directionally your comments on fiscal 20 to 22 I know, it's early days, but.
How should we think about the broader contour the moving pieces by segments clearly GNP with an addition of fake you would have three months of additional drilling capital, but how should we think about completions and any comments on 2022 directionally.
John you want to think Dnbi side sure.
2020.
22, if we see or whether we see the approach of lighting itself. The online date there.
There probably be a bit more costs going into fiscal 22 related to completion and bringing those all those wells online.
So 22 may be a bit higher but then going forward, we will see that drop again, we go back to that one and a half to two rig pace and then to be pretty pretty consistent in that 350 to 400 on a go forward basis.
And I think when you when you consider the rest of the system.
The gathering capex overtime I would expect to be route to be relatively flat. We've made a big investment in that over the years that we're now really able to to monetize.
As you know we'll be building FM 100.
Which.
Better than $200 million project of the bulk of that will be spent in 2021, so we'd expect a big drop in pipeline Capex and in 2022.
And then on the utility it's it's likely steady as she goes kind of in that $90 million to $100 million area. So when you consider the the big jump in revenues that will have on the pipeline side of the business and the big growth in in.
In Senecas production, we'd expect to be meaningfully free cash flow positive in.
In 2022 and beyond.
Appreciate the details.
On just sticking to 2022 looks like.
You have a very solid hedge book for fiscal 21, what does the hedge book look like or protection looks like for 2022, and given natural gas dynamic how what's your hedging philosophy, and how you're thinking about sensitivity to gas prices in 2022.
Yes, we've been methodical and trying to build a book for 22, if you look in our our release last night in the slide deck, you can see that we've.
We've added a fair number of physicians there.
Our philosophy is to layer in hedges over.
Two or three year period with the goal of being in the two thirds hedged area of prior to the start of the fiscal year see look where we are on fiscal 21 were.
Were better than 75% hedged.
We are less than that for fiscal 22, but as we go through time we.
Our state as we go through fiscal 21 will.
We'll grow that book to be again in that two thirds.
Area for.
For that fiscal year.
Great and if I could sneak one more in.
Thanks for the color on where the second grade is going to go but just wondering how you operating.
Or thinking about operating the recently acquired assets differently from the previous owner when thinking about is utilization of infrastructure and our supplier chain anything operationally that you're doing differently.
It really the biggest benefit as on water costs. They had a fairly extent they had a number of freshwater impoundments that we're able to utilize and.
And so build early when we know we're going to be active in that area.
They had a waters of produced water stored facility as well and that's really where so far it's only been a couple of months, but thats, who we have really seen some of the cost savings is driving down our water costs.
You know as as we continued to optimize that they had a lot of wells that sorta needed to be upgraded to our standards and so we're going to spend a little bit of time doing that and that will also help but at least early on it's just water costs are really the key driver.
I appreciate the detail. Thank you.
But.
Your next question comes from Tim Winter from Gabelli funds. Please go ahead.
Good afternoon guys.
Our axon on the updated guidance.
I was thinking there.
Can you talk a little bit about given evolving us energy policy, where the California oil pit patch fits into your strategy and maybe a little bit more expand on the.
Meaningful free cash flow opportunities in 22, what types of things you might.
It might be looking at a given.
Both the world's moving towards.
Zero carbon economy.
Im sure John you want to take the California based share.
California remains a key piece of our portfolio.
It generates.
On every year it generates significant cash flow in even at $40 going into fiscal 21, we're looking at.
Turning to what we're going to stand we're looking at maybe cash flow free cash flow in the low Thirtys abhi.
Obviously when prices are higher that increases significantly, but it continues to be a great cash flow generator for us.
I guess I hopefully that answers your question on that Tim.
Yes. Thanks, Thank you.
And on the in terms of of 22 and beyond.
Thanks.
I think we'll keep our options open we as management and the board.
Regularly review the strategic direction of the company and.
And consider opportunities across the value chain of the natural gas business.
I certainly get your point that the world is looking to be carbonized and that could create opportunities for us as well.
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And we'll have our eyes open for for things that can potentially add value for our shareholders.
Okay, great. Thanks, Dave and congrats again on the guidance. Thanks.
Thanks, Tim.
As a reminder to ask a question press Star One. Your next question comes from John Freeman from Raymond James. Please go ahead.
Hi, Good morning. This is Gordon I'm going in for John.
Im just wondering kind of a.
Quick question on them.
54 I am.
Notice that the average kind of capex.
On the losses come down.
Quite a bit of across the board.
I'm just trying to.
In that area.
How much of.
The decline is related to kind of.
Service cost pricing, how much revenue will be structural and kind of longer term.
Yes actually EPS.
Good point.
Obviously, a lot of that has been service cost driven we've seen probably 10% to 20% drop over the last year year over year having.
Having said that we're also seeing costs on a per well basis, we're seeing increased efficiencies with respect to our Utica program.
We're drilling these wells faster and faster.
And and I think that will be that will continue to be a driver in helping us reduce cost, but really the bulk of it has been the two combined over the past years. So there's still some running on especially in the Utica side.
But but really it's been a good.
Dramatic drop from year to year, and obviously, a part of that is due to service cost.
Got it that makes sense.
My follow up is.
I'm, just trying to get a better handle.
Hi, you guys still on.
The big determinants of six Bcf that you guys curtailed.
In this quarter, how much I guess, what's the split between that you did.
And as that all kind of like you said before.
Related to how much spot exposure you would have.
Between the different basins.
Yes, that's exactly right and I don't have the split between our three key receipt points I'd know it was we did have we do have curtailments both in the W. da.
Tioga and Lycoming I don't have how that split out, but that's exactly right. It's really a function of the pricing at each of those points with what spot exposure, we do have and if it drops below a certain level than we'll shut those wells and.
Okay.
That makes sense, thanks for taking my questions.
Yep.
That was our last question at this time I will turn the call back over to the presenters.
Thank you Mike.
We like to thank everyone for taking the time to be with us today a.
A replay of this call will be available. This afternoon on both our website and by telephone and will run through the close of business on Friday November 13, two.
To access the replay online please visit our Investor Relations Web site.
Investor Dot national fuel gas dotcom and to access by telephone call. One 805, 8583, 67 and enter conference I'd number 5657 zero or six.
This concludes our conference call for today, Thank you and goodbye.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating you may now disconnect.
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No.
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