Q3 2019 Earnings Call
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I'd like to drive for Antero resources.
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First name debuted last name Brown.
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The conference is being recorded.
Thank you.
Third quarter 2019, Investor Conference call.
We'll spend a few minutes going through the financial and operational highlights and then we'll open it up queuing day.
I'd also like stretch into the home page of our website at Www Dot Antero resources Dot Com, where we have provided a separate earnings call presentation that will be reviewed during today's call.
Before we start our comments I'd first like to remind you that during this call and Taro management will make forward looking statements such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties many of which are beyond anteros control.
Yeah.
Actual outcomes results could materially differ from what is expressed implied or forecast in such statements.
Today's call May also contain certain non-GAAP financial measures.
Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.
Joining me on the call today, our Paul ready, Chairman, and CEO , and Glenn Warren President and CFO .
Ill now turn the call over to Paul.
[laughter].
Thank you, Mike and thank you to everyone for listening to the call today.
In my comments I will provide.
An update on the considerable progress we've already made on our well cost savings initiative.
I will also discuss meaningful operating cost reductions that we have achieved across our business that we expect.
To further reduce going forward.
Glenn will then highlight our second quarter financial achievements and our expanded hedge position that now covers essentially 90% of our projected natural gas production through both cow 20, and Cal 21.
He will conclude with comments on our balance sheet and liquidity position.
I'd like to just to start by discussing the expansive cost savings efforts underway at Antero.
Over the last year, we have been intensely focused on reducing the overall cost structure at antero.
To make us more competitive in a lower for longer commodity price environment.
This process includes a line by line review of every expense item throughout the company.
Through this comprehensive review, we have identified the potential to remove $250 million from our overall cost structure in 2020 alone.
As detailed on slide number three titled cost reduction strategy overview.
The majority of these significant reductions will come from lower well cost and reduced LOE eight.
Firm transportation mitigation and Gionee reductions account for the remaining savings.
These efforts are already delivering results as our third quarter DMC Capex was $290 million the lowest quarterly spend since our IPO in 2013.
Further due to the cost savings realized to date.
We reduced our full year 2019, DMC capex budget to a range of 1.275 billion to $1.3 billion.
Nearly 800 million dollar reduction from the midpoint of our original 2019 guidance.
Despite this capital reduction we increased our annual production guidance to the high end of the prior range, a 2% increase at the midpoint.
Now, let's discuss each of these items individually.
Last quarter, we announced a well cost savings initiative that targets, 10% to 15% reduction in well costs on a per lateral foot basis.
Our approximately $1.2 million to $1.7 million per well.
Turning to slide number four.
Titled.
Targeted Marcellus well cost reductions.
We began with our January 2019, well costs at $970 per foot.
It was assumed in our budget.
Today, our all in well costs are $895 per foot.
Which equates to savings have nearly $1 million per well.
And by all.
All in I do mean, all in as our well costs include pad roads in facilities costs, which are at an average $900000 per well or $75 per foot.
The savings already achieved our substantially ahead of the second half 2019 target of $930 per foot that we announced last quarter.
We were able to accelerate localized water blending operations during the third quarter, which reduced flowback water costs ahead of schedule.
Our team was able to quickly execute a development plan to blend flowback water at the pad sites being completed during the third quarter, which was ahead of our initial timeframe.
This acceleration illustrates the direct benefit of our relationship with Antero midstream as compared to the long lead time that would have been required. If we were working with a third party midstream provider.
The closure of the Antero Clearwater facility also accelerated well cost savings as we increased blending in order to minimize the high wastewater injection fees.
And trucking costs associated with it.
Also contributing to lower well costs was dryer completions.
During the quarter, we use fewer barrels of freshwater per foot in approximately 20% of our completion stages.
Looking ahead, we are targeting a well cost of $830 to $870 per foot in 2020 and have outlined several savings initiatives to achieve this call all of which are within our control.
By the first quarter of 2020 , we anticipate an average well a fee of $880 per foot with further declines expected as we move through the next year.
Turning to slide number five titled.
Marcellus drilling and completion efficiencies.
We also to continue we also continue to realize cycle time improvements.
During the third quarter.
We set new records for our average lateral lengths.
Average lateral feet drilled per day, averaging 6000 feet per day, and setting a new one well world record drilling 10067 lateral feet in a day in 24 hours. This dramatic increase in lateral feet drilled per day.
Has reduced the days to drill as well.
To 11 days from spud to spud.
That's a 62% improvements since 2014, despite having increased our average lateral length by 42% to 11500 feet.
Further the reduction in fresh water use in our completions helps increase our completion stages per day.
Which increased to a new quarterly record of five point.
Nine stages per day, and we also set a new record a one day record of 11 stages in a day.
Slide number six title.
Antero water savings performance.
Highlights the reduction in elderly and capital driven by our transition into blending and reuse of producing flowback water.
We expect to increase our blended water for reuse to 40000 barrels a day on average in the fourth quarter from 10000 barrels a day on average in the third quarter. This increase in blending operations combined with reduced trucking miles and lower negotiated trucking rates.
Is projected to result in over a four dollar and 50 cent per barrel decrease in water handling expenses.
Compared to the first quarter of this year.
As shown in the Green line on the chart. We expect this per barrel decrease will translate to approximately $57 million in cumulative 2019 savings relative to our initial budget.
[noise] slide number seven titled Water savings.
Driving aloe, we lower illustrates the overall aloe any impact from the water savings initiative.
Our third quarter Aloe Lee of $36 million was down 17% sequentially.
Historically produced water costs represent 80% of our alley.
By transitioning our operations to localize blending and reuse starting in August and shifting away from the Antero Clearwater facility in September as the facility was idled.
We were able to drive down our low a substantially.
We expect even further reductions in L. are we going forward as we benefit from a full period of these cost savings with fourth quarter App Cielo absolute aloe, we expected to decline another 15%.
For nearly $5 million.
As it relates to our 2020 outlook, we anticipate Luis savings of at least $60 million from these initiatives compared to 2019.
Our goal is to land, 100% of our flowback and produced water.
This is achievable we believe.
We have actually reuse to 100% a number of times and set a new record just this last week blending 60000 barrels a day. So we believe it's quite possible.
Turning to slide number eight title firm transportation mitigation and guidance update.
We continue to work aggressively at mitigating our excess firm transportation costs.
We recently released 250 million cubic feet, a day of excess FTD to third parties. During the months of September 2019 through March of 2020.
This offload will reduce our net marketing expense by $15 million over the next several months.
And led to the lowering of our 2019 net marketing it at marketing expense guidance.
By two cents per Mcf fee at the midpoint.
We continue to see at attractive opportunities to market some of our excess firm transportation capacity.
Driven by the recent widening in local basis at attractive spreads to the Midwest and Gulf Coast.
As Ilitch illustrated on the chart 2019 is our peak year for firm transport capacity at 4.6 Bcf a day.
At Anteros option. This capacity comes down by 100 to 200 million cubic feet per day, each year going forward declining to 4.1 Bcf a day in Cal 23.
We expect.
To have essentially all of our premium firm transport organically filled by the fourth quarter of 2021.
Switching to Gionee expenses.
We recently lost launched a cost savings initiative targeting a 10% or 14 million dollar annualized run rate reduction in mid 2020 by mid 2020.
These savings will come through employee head count reductions that occurred earlier this year.
Natural employee attrition and a reduction across the board in business operating expenses.
In summary, we will remain steadfast in reducing our overall cost structure with a goal of being a peer leader in returns regardless of commodity cycle.
Our relentless effort to reduce costs has already delivered benefits as highlighted by 2019 capital guidance being reduced 4% to under $1.3 billion.
Despite reducing capital we are increasing our production target to the high end of our initial guidance range of 3.15 to 3.25 Bcf equivalent per day.
Highlighting the improving capital efficiency of our assets.
Looking ahead with these lower costs, we now expect DMC capex to be under a $1.2 billion in 2020, while delivering production growth in the range of 8% to 10%.
This preliminary target is supported by our peer leading hedge positions with 90% of our natural gas protected through Cal 21 at prices well above the strip.
Based on the current commodity strip.
We expect our 2020 modest growth program to outspend.
By 102 $150 million.
It's important to note that our capital program will remain flexible depending on NGL prices and can be reduced accordingly in order to prioritize the strength of our balance sheet.
With that I will turn it over to Glenn for his comments.
Thank you Paul turning to slide number nine titled industry, leading natural gas hedge position, we continue to add to our hedge position during the third quarter and through October the Orange line on the graph represents our hedged or fixed price swaps prices for natural gas. We're now 91% has some natural gas in 2020.
An average price of $2.87 per MBT view, and 89% hedged in 2021 at an average price of $2.80 per it would be to you assuming the midpoint of our 8% to 10% growth target in 2020, and 10% growth target in 2021.
It's important to note that we continue to offset our annual net marketing expense with hedge realizations based on strip pricing today, our hedge realizations will more than offset our net marketing expense through the year 2021. It is notable that we remain the only publicly traded use producer that is 100% here.
Hedged on expected natural gas production for the remainder of 2018 and have significantly more hedge protection in 2020 in 2021 that almost all of our Appalachian peers. This is an important investment attribute in a bear market for gas.
Turning to slide number 10 titles C plus NGL hedges. We also had been actively adding NGL hedges and were able to take advantage of the global price spikes. Following the missile attack in Saudi Arabia. In September we are currently 50% hedged on our expected C plus NGL volumes for the.
Fourth quarter and are now 28% hedged in 2020.
We have hedged 93% of our expected pentane horsey five volumes in 2020 at $47, an 84 cents per barrel and over 60% in 2021 at $44 in 94 cents per barrel Sci Fi volumes were first hedged at a percent of Wi Fi than the Wi Fi price was locked.
With a fixed price oil swaps, resulting in a fixed price for our C. R. C volumes. So our combined C plus oil production volumes estimated to be 27000 barrels a day for the fourth quarter of 2019 in closer to 30000 barrels a day for 2020.
These volumes really represent our Wi Fi oil exposure going forward, and we have hedged, 85% and 50% of that volume for the fourth quarter of 2019 and 2020, respectively.
We will continue to work toward managing our NGL price exposure by adding hedges across our domestic European and Asian markets.
Third quarter C plus NGL price realizations averaged only $22 at 53 cents per barrel. Although there was a seasonal NGL price decline from the second quarter were once again able to realize a premium to Mount Bellevue prices due to our industry, leading exposure to the international LPG market.
Through our capacity on.
The immune to Gary's too as illustrating the bottom left table on slide number 11 title NGL transportation delivering premium pricing, we shipped 54% of total C plus net volume on Mariner East two for export in the third quarter and realize at 12 cents per gallon premium to Mount Belvieu at Marcus Hook.
The remaining 46% of C plus that volume was sold domestically or 13 cents per gallon discounts to Mont belvieu pricing that hopedale.
This resulted in a blended price, which was a one cents per gallon premiums from Mont Belvieu pricing.
And the table in the right hand side of the slide we provide guidance on NGL realizations relative to Mont Belvieu pricing for the full year of 29 team.
Looking forward, we see the third quarter is the trough in NGL prices. This is supported by the recent price strengthening seen since early October as depicted in the chart on slide number 12 title in NGL price improvement.
Based on current strip prices, we anticipate a $5 per barrel improvement in realize C plus NGL prices in the fourth quarter of 2019, the improved pricing has been due to a combination of factors, including seasonal effects as we transition into winter increased Doc export capacity on the Gulf Coast.
Ongoing global supply disruptions following the incident in Saudi Arabia, and continued robust international LPG demand.
It's important to note our leveraged NGL prices as the second largest NGL producer in the US for 2020 for example at $5 per barrel improvement in the roughly $25 per barrel C plus triplet price that we're using in our estimates would generate an estimated $170 million of additional cash flow.
Thereby eliminating our estimated 100 to 150 million dollar outspend in 2020.
As we highlighted during the second quarter call heading into 2020, we see fundamental tailwinds to NGL prices driven by additional export expansion capacity projects, along the Gulf Coast and East Coast at March Marcus Hook that will provide relief distressed and supply and support domestic prices.
On the international front, new PDH plants in China, combined with incremental in port capacity across India. In Europe are expected to drive continued strong demand in the international markets.
Moving on to slide number 13, titled strong financial position for low price environment.
Maintaining a strong balance sheet remains the top priority at Antero.
Our current balance sheet strength positions us well to whether any sustained downturn in the market, we have reduced absolute debt by approximately $700 million over the past few years, resulting in a mid two times leverage today.
We have $1.2 billion the value in our ownership that provides over $200 million per year of steady cash flow in the form of dividends and our hedge mark to market value is currently $807 million.
Our borrowing base was reaffirmed at $4.5 billion during the spring Redetermination.
This October we added RBC to our lending group with a $140 million lender commitments, increasing our total bank commitments to $2.64 billion.
We currently have only $275 million drawn on the facility and $700 million of letters of credit. So today, we have almost $1.7 billion of committed liquidity under our credit facility plus almost $1.9 billion of uncommitted first lien capacity.
While we have no plans to utilize the additional firstly capacity the combined $3.5 billion of first lien borrowing capacity services, a backstop that would enable antero to repay both his 2021 and 2022 bond maturities with new first lien commitments, if the unsecured market doesn't mature.
Generally improve.
And this backstop is supported by 10 Tcf the PDP reserves that the dividend stream from am and almost $1 billion of hedge value.
And Thats a bank pricing.
Other liquidity options include asset sales and further cost reductions some of the asset sale alternatives or hedge monetizations, which we've done in the past.
The sale of am shares, which we did in the simplification earlier this year and land sales, which we have done in the past.
Also recall that we have 84% average and arise in the Marcellus and the sale of overriding royalty has been has been demonstrated to be a viable asset monetization strategy well. We don't rank that is what has an attractive alternative for us as our net interest and production is core to antero.
Additionally, further cost reductions will strengthen a ours cash flow and borrowing base capacity above the estimates provided above.
At the time of our spring Redetermination, we had not yet announced our well cost savings initiative elderly reduction or gionee cuts the continued execution.
On these important initiatives will support our borrowing base capacity next spring.
Any reduction in GP and LP costs could materially enhance the cost reduction initiatives.
The key takeaways, we have a bunch of refinancing and liquidity alternatives available to navigate a lower for longer commodity price environment.
For an integrated natural gas and liquids producer with the scale that antero enjoys there's a spectrum of alternatives available. It's not a binary situation importantly, we can be patient as our cost reduction initiatives play out and believe that the bond market will offer attractive refinancing rates to solid upstream credits over the next year particular.
With some cyclical commodity price improvement.
With that ill now turn the call over to the operator for questions.
Thank you.
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One moment, please while we pull for questions.
Our first question comes from Welles Fitzpatrick with Suntrust. Please state your question.
Hey, good morning.
Morning by Wells.
You guys have obviously taken taken advantage of the recent this and volatility at that Dom South and into can you can you talk to how you see those two hubs developing going forward and.
Yes through year end in in 20 years is that volatility some you see is.
Transient or or do you think it will continue through through year end 2000.
I think it'll continue probably through year end 20, there's still some constrained in the regional pipeline systems that being for example, the.
Tetco.
Shut down with a resumption it'll probably not resume at a lower takeaway capacity, but we just see things are.
Little bit constrained there in the downtown.
Go him to market I think when the spreads widened to Chicago, then the distress gaskets bought up at a premium to M. Two are down south because there are number of.
Shippers, including ourselves that by the distressed gas and move it. So so it goes up and down its.
Volatile due to the physical constraints and then.
When spreads widen than.
It gets bought up and then when spreads are not don't justify the variables that at Languishes again. So we think until there is more pipe buildout of out of that northeast area that is going to go up and down depending on whether anda.
Pipeline capacity as it comes online or doesn't.
Okay and in in that type of environment.
Is it fair to assume that you guys would be able to get some more.
Release capacity agreements.
Do you think theres depth to fit to those type of deals.
Yes, yes, we do so.
We've we've demonstrated were perfectly willing to release some capacity to.
The other parties in the spreads justify that and.
Or weekend by the distress third party gas and collect a margin. So we're we're constantly looking at both those have options.
Okay and then just just one last one for me, it's I suppose it's less applicable to all but theres been some chatter about.
Pipelines demanding extra letters of credit that can be triggered by by one thing or another is is is is that something that could potentially manifest in 19 or 20.
And what would the trigger points that maybe we should pay attention to be for that.
Yes, we have looked through all of our agreements when we look at.
Not all of our ft agreements there is about.
Three of them that have provisions that if we get the downgrades there would be an increase in letters of credit those downgrades are actually.
Actually tied to what our ratings where at the time of the agreement. So it's back to 2014. When we were rated a couple notch below where we're at so right now that would not affect us, but if you do have further downgrades in the future there could be a little bit of LC increases.
Like we mentioned right now there is about 700 million about Lcs.
Order of magnitude of those are increases are about 100 to 300 million, but it would have to be a couple notch downgrade premiere.
Okay, Thanks, and congrats on the the strong stronger.
Thanks Wells. Thank you.
Our next question comes from Bryan singer with Goldman Sachs. Please state your question.
Thank you good morning.
We saw significant pickup in the weighting toward NGL and as a percent of the total production mix. This quarter can you breakout where and why you saw this and how you see that evolving through 2020 next year do you see.
Different range of liquids growth versus the 8% to 10% total growth kind of.
Well, we focused on.
Highly liquids rich locations from 12, 50 to 1300, BT use or you're just seeing that incremental increase in the proportion of liquids and I'd say, we expected to be fairly steady in that range over the next year Brian .
Great and then.
Hello.
Highlighted multiple cost reduction initiatives reductions in marketing expense and yet at the strip, you're still out spending or expect outspend cash flow modestly after some of the one off benefits.
That does your 100 to 150 million an outspend assume the full impact of the cost savings initiatives discussed today and beyond the commodity price improvements what do you see as the drivers of.
Upside to that free cash flow arrangement.
Yes that forecast does include the Ela, we improvements the though the well cost improvements that's all all baked end and hopefully those numbers are conservative and will even do better than those numbers, but we also mentioned our I mentioned in my comments just that.
There are other or other cost initiatives under way outside of that on the midstream transport side. So we're having a numbers discussions there. So you could see some improvement.
There overtime and that can be material as well.
And I guess with regards to be conservatism baked in if there is in area of focus where you think theres a some more significant opportunity for cost reduction of the multiple initiatives. You you talked about what do you point that more towards the well cost the ela, we or the.
Or the midstream side.
Yes, I would say, both well costs and Ela we.
I think on the well cost side, we feel pretty good about getting below eight hundreds per per foot there and so hopefully we'll outperform on that and so.
But the GP and Ti cost that's all negotiation that takes place over time, we mentioned that on previous calls.
There's no guarantee that any of it gets done but some of it does it could be pretty pretty material.
Great. Thank you.
Thank you view.
Our next question comes from really CD with Guggenheim Partners. Please state your question.
Yes.
Yes, sorry, guys so last year.
The I guess the first question.
First of all congrats on a very eventful quarter, so I'll try to get a few these and.
GPN T O I should say the cash production expense outlook for 2020.
What is that range now.
Yeah, we haven't put out a range there, but it's similar to this third quarter and think it's between 215 to 25.
Okay.
And on the the water side.
How much more can you press that.
With regards to it looks like a 100% recycling was.
Sort of somewhat isolated maybe I can be a lot more broadly applied them that in and the 10 goes to 40, so what.
What could be a pie in the sky number eventually.
On the water handling.
Well I think as certainly within our sites to Bosh, we could see.
It takes planning it and so on but as much as a 100% blending of all of our.
Flowback and produced water and so as our production grows.
I think steady state right now roughly steady state with for three Frac crews 45000 barrels a day with four crews that we're operating right now the flowback and produced is 60000 barrels a day and our teams are.
Handling that quite well, we just keep getting better at it so.
Do you think thats achievable that as we go forward, we had a bigger production base there will be a little more produced water.
And varying between three and four frac spreads will be in that 50 to 60000 barrels of a producer flow back and I think thats all achievable and.
It's going to be our old L., we was above $10, including Clearwater $10, a barrel and we're getting it down into the mid fours now so.
I see there could be quite a bit of saving certainly above the 50 million dollar a year.
So so feel optimistic about that are.
Utica volumes are pretty low there about 4000 barrels a day right now we take that to injection and it's.
Pretty pretty low cost into under 450, a barrel between injection and tracking since its near the injection site. So.
So anyway, we do think that Hello, easy and is as we've said in our press release or in our remarks water is about 80% of Varello 80, So as we make big strides on the water side, we can really reduce generally.
Hey, Thanks and final one on back to the LC.
Discussion.
Other alternative markets too.
Kind of put the money out there.
Hey from.
The credit facility.
It seems like offshore producers with FERC regulated exposed to FERC related pipe seem to be able to do that in alternative markets.
Yes, you much that's a good point, we are looking into that there's there are the surety bond market out there is something we're exploring the in order to satisfy some of those LC requirements. So that could definitely offset any LC increases if we do get downgrades.
Okay.
So the you wouldn't you do it on the incremental amount on the current amount is that are that we could actually replace some of our existing Lcs was surety bonds as well.
Okay got you.
Terrific guys nice job. Thank you.
Thanks Sparsh Bush.
Our next question comes from Gene truck cycle with Stifel. Please state your question.
Good morning, and thanks for taking my questions. My first question is on production. Thanks to that we have seen yet to date, maybe you could provide some color on what has to even production knowledge format.
Well, we're seeing great well performance all year, and so thats really what it when it comes down to just beating in.
Part of it is getting as wells on sooner than expected you know so we.
We certainly schedule everything out for the year in our budget and when we beat that budget from a timing standpoint. The production comes on sooner and drives the quarterly production up up higher so it's a combination of those two well performance and timing.
Got it my second question is on oilfield services.
So you kind of highlighted a well cost savings, which mostly driven by itself have any Sal south helping you said just I'm I'm just curious like how much of well cost savings that you laid that to vendetti landed cost to toxins and maybe you can just provide general comments on well tell extended deflation.
Manny.
Not the Lisa.
Yes, there is.
Definitely.
Cost deflation with our vendors and we've been working with them for a number of months now Weve made requests and contacted and there are several hundred vendors that we're involved with that contacted them all and asked for a certain discount and virtually all.
Been willing to.
To give that to us and then we've asked for extensions through the next year and many have rallied fourth and so.
We feel that all our interests are in the same boat and.
So they definitely want to continue to work with US we were very active and so they've been willing to caught and so feel good about that sticking for the foreseeable future.
Can you talk about just how you think about that asset now its portfolio management.
But it does have tremendous option value there some great gas dry gas locations over there and some up dip liquids rich locations. It's just at this point in time and a very low price environment. It makes sense to keep your costs optimally low of course, and when you drill in the same area, you're able to use all the flow.
So backwater you next completion side. So just makes sense to keep the rigs in the Marcellus for now, but the Utica those are important locations that are in our in our inventory.
If I could just close out with one more just.
So you know some some effort on the share buyback side. This quarter. Obviously, there is still projected outspend going on you.
You have.
Increased I guess your lender commitments by welcoming RBC some of your your corporate bonds, obviously traded at discount I guess, how do you. How do you think about now one perhaps leaning on the revolver I guess tie their buyback some debt or shares.
And I guess one of the conditions that cause you all to look at the share buyback as a good use of funds.
We want to remain flexible on that we were optimistic here in the last quarter and picked up a few shares I think you'll see us do that some overtime, but it's not going to be a heavy program until we see better commodity prices and stronger cash flow. So we want to preserve the balance sheet primarily.
We certainly have the option to to buy a buyback bonds and you may see as to some of that overtime as well we've got plenty of liquidity for that so we'll be opportunistic I think is the bottom line.
Okay. So is the share buyback announced it just intended to offset sort of the natural dilution from employee programs.
No.
No. It's just an opportunistic buying of shares in a very economic thing to do it at these kind of price levels.
Thank you guys.
Thanks, David.
Our next question comes from Karl Blunden with Goldman Sachs. Please state your question.
But the timeline on the comments on the balance sheet just.
Looking at your maturities 20 ones and 20 twos.
Interested in how you think about.
Addressing those do you need to come up with the solution for addressing them together.
Or perhaps be more patient I think some of your comments suggested if the market remains challenging.
Actually addressed the 20 ones before then turning your attention to 20 twos I'd be interested any any thoughts on that.
What makes you decide between secured and debt sooner and or waiting for the unsecured markets to open up.
Well the good is we can afford to be patient we have a lot of time. So you really haven't seen the bond market shut down for even DNP for more than a few quarters. So we don't think this will last you know for a year or let's say, but we can afford to be patient on it and.
We look at both of those maturities for sure are not as a bundle, but we look at both of them and.
Whether we go to the secured market or not that kind of his hands on how things play out over time. So it's a very fluid dynamics situation. When you get into these kind of market dislocations and use of to stay on top of it be aware and be ready to execute if there's something attractive.
Okay that makes sense then when you think about kind of the market window required to allow you to keep that flexibility as it 12 months, maybe it's not nothing.
Six like that but when when the bank start taking a look more closer look at your maturities. It tends to be about 12 months that right way to think about it that.
Basically as a whole 2020 to make a move and clarify your parts or.
Maybe have less or more time I'd be interested in anything on that.
I think thats a good way to think about it on the you'd like to stay out of going current on your balance sheet. So that's that's the way to think about the 2021 anyway Thats right.
Hi, I really appreciate it thanks.
Thank you. Thanks go.
Our next question comes from Sean Sneeden with Guggenheim Securities. Please state your question.
Hi, good morning, and thank you for taking my questions.
Sure.
Yeah, I guess you on the kind of small.
Yes, the monetization that you're doing over the winter I guess, you could you share what kind of end market is the pipe is going to and you know I guess you. It looked like be kind of implied charge there it's going to roughly 30 cents.
Just kind of curious you know, how we should be kind of thinking about that.
It was that.
Just a function of kind of tougher in basin dips that kind of drove that decision or.
Any kind of commentary around opportunities beyond the beyond this winter.
Yes, Sean we're we're looking at those all the time.
And.
The choices, where there too.
Do an A.M.A. asset management agreement and.
Lee something out in a sense for an extended period like we did here six or seven months to go from them to pool over to Chicago.
Or to manage it ourselves and a nine sell distress third party gas.
Moving it in that direction and so.
That's right roughly 30 cents and so we and others Theres a pretty good market out there for a for release capacity and so others. This spreads in saw them into forwards that they could lock in.
And so we made the decision to let go of though those in mass and so that the flow path would be.
Rex West found out of clearing 10, and it connects with a couple of pipes that we have MGT and then GPL.
Over in a eastern Illinois, Scotland, and Moultrie, Illinois ended the Chicago market. So they're generally a into the Chicago City Gate.
And so good spreads and so.
Those parties are working that and.
The spreads have been positive.
Quite a bit lately with this cold weather, so I think they're doing well and so.
So that's what we look at all the time and so those emerge.
Quite often we're looking at spreads and.
Whether we want to sublet as it were for some period or use it ourselves for our own gas for the very best realizations or buy and sell gas on the day in makeup see.
Some of that marketing expense that way so ever choices.
Got it that makes sense.
And then I guess.
About you kind of the you meet its versus kind of feeling TB cases, so I guess, you talk a little bit more about how you're thinking about that and I guess, specifically since you <unk> you would look like you know the marketing that's been watching producers to kind of go more maintenance case.
Yeah.
How do you think about slowing down in and I guess along with that.
Is there any ability to renegotiate you with.