Q3 2020 Antero Resources Corp Earnings Call
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I'd now like to turn the conference over to your host Michael Kennedy Senior Vice President of Finance.
Thank you for joining us for Anteros third quarter 2020, Investor Conference call.
Let's spend a few minutes going through the financial and operational highlights and then we'll open it up for Q at night.
I'd also like to direct you to 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 would like to first remind you that during this call Antero 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 a number of risks and uncertainties. Many of which are beyond anteros control actual outcomes and 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 join.
Joining me on the call today are Paul Rady, Chairman and CEO, Glen Warren President and CFO, and David Catalano, Vice President of liquids marketing and transportation.
I'll now turn the call over to Paul.
Thank you Mike.
I'll open by commenting on the progress we've made on our asset sale program.
As detailed on slide number three entitled assets sale refinancing and debt repurchase progress.
We have close to $751 million or asset sale proceeds today.
The proceeds we EPS.
We seem to have enabled us to reduce debt by approximately $620 million.
Since the asset sale program began in the fourth quarter of 2019.
We continue to monitor the asset sale markets any.
Any additional proceeds will be used for further debt reduction.
Now, let me update you on our cost savings momentum during the third quarter.
Our well cost savings initiatives continue to drive our costs lower.
Actual well costs during the third quarter averaged $640 per lateral foot benefiting from a long laterals that averaged 15900 feet during the quarter.
Normalized for a 12000 foot lateral.
Well costs were $675 per foot or 17% below the initial 2020 well cost target.
Note that our well costs are all in.
And they include road pad and facilities costs.
We turned in line 27 Marcellus wells.
During the quarter and these wells had an average lateral length of 11900 feet.
15 of these wells have 60 days of production history, and the averaged 24 million cubic feet equivalent per day, helping to drive our strong production performance during the quarter.
Now, let's discuss the point out regarding our firm transportation portfolio.
Turning to slide number four.
Titled.
[noise] that marketing expense and F. She commitments declining.
During the third quarter.
We gave notice to release 300 million a day 300 million cubic feet a day of firm transportation capacity during 2021.
Now let me just make a clarification what we're talking about here is releasing 300 million a day of long haul Interstate transport such as the big pipes to the golf the mid west and to the Appalachian M. Two pool.
We received a little bit of feedback have little misunderstanding.
Certain people thought that we're talking about antero midstream capacity, that's not what we're talking about we're talking about the long haul capacity.
The reduced commitment and is expected to lower our net marketing expense by $25 million next year and $60 million in 2022.
As shown in the chart on the left hand side of the slide our firm transportation commitments declined by 810 million cubic feet a day by year end 24.
Chart on the right side highlights the approximate $100 million reduction in annual demand fees by 2024, resulting from fourth from the release of this 810 million cubic feet a day of firm commitments.
To summarize this point 2020 is our peak year for firm transportation expense as these commitments step down each year going forward.
The result is a lower cost structure at antero, even in our sustained maintenance capital spend profile.
Slide number five titled.
Firm transportation provides stability.
This highlights the benefits of our firm transportation, our ft portfolio. The Red line in the chart represents the Appalachian basis differential which has averaged 82 cents.
Below Nymex going back to 2014.
Our premium from transportation has delivered a.
Five cents discount to Nymex over that same time frame.
It's also worth noting that since gaining access to our entire ft portfolio in 2018.
Antero has been able to realize a six cents premium to Nymex to date.
During the third quarter. This benefit was even more pronounced as Appalachian basis differentials blew out yeah.
Given the limited excess takeaway capacity in Appalachia and maintenance downtime. This fall regional prices have recently traded at $1.50 below Nymex.
These weak prices have forced some producers who lack adequate takeaway capacity to shut in and curtailed production, which can lead to high volatility and cash flow and operational performance.
Conversely, anteros ft portfolio delivers reliable results flow assurance premium prices and the ability to readily hedge liquid Nymex Henry hub prices.
Now, let's turn to slide number six.
[noise] titled Appalachian Takeaway capacity is a strategic advantage this.
This chart depicts the tightening takeaway capacity in Appalachia in the Appalachian basin in the vicinity of the yellow Arrow on the chart.
Which has led to today's wide basis differentials the.
The solid Red line is the historical production in Appalachia with the dotted Red line showing the growth projection through 2023.
The Green line is the regional basis differential.
As you can see as capacity tightens, where there is white space on the chart.
The regional basis blows out, particularly during the summer and shoulder months yeah.
Even with the potential start up a new pipeline capacity such as having VP next.
The expected call on Appalachia supply is projected to lead to sustained wide differentials in the base basin.
With what we refer to as right sized premium firm transport Antero is the best positioned natural gas producer in Appalachia to take advantage of rising Nymex natural gas prices without the risk of widening local basis are being forced to shut in Peru.
Option.
When we talk about Rightsized, we're considering both volume.
Tariffs.
And destination or delivery points, dropping the unneeded or undesirable Martin destination, so it'll be quite strategic.
As we look to downsize our EFT team portfolio.
In conclusion.
I'm extremely proud of the job anteros operating team has done.
With optimizing our drilling and completion operations and delivering significant cost reductions. These.
These efforts not only led to a record low quarterly capital expenditures, but.
But also to the quarterly production performance that exceeded expectations and delivered strong quarterly financial results.
Through the first nine months of the year, we have turned in line, 91% of our expected 105 completions in 2020 so.
So we anticipate another decline in capital spending during our fourth quarter, resulting in annual drilling and completion capital expenditures of $750 million.
Importantly, we expect to generate approximately $175 million to $200 million of free cash flow during the second half of 2020 based on today's strip prices.
With that I will turn it over to our vice president of liquids marketing and transportation, Dave can along though for his comments.
Thanks, Paul.
Let's turn to slide number seven in like begin by adding some color on the NGL and LPG macro environment.
In the aftermath of the March Opex, plus price war, and COVID-19, pandemic, the resulting decline in rig and completion crew activity in oil focused shale basins has set up expectations of a prolonged period of depressed us oil production.
Thus far that is what has materialized a decline in flattening of oil production, which has resulted in a decrease in associated NGL production from the oil focus place but.
The chart on the left hand side of the slide illustrates that U.S. NGL supply forecasts have declined by 1.1 million barrels per day since the beginning of this year we.
We believe it may take three to four years for us NGL production to return to pre COVID-19 levels.
The chart on the right hand side of the slide highlights the expected surplus of LPG export capacity along the Gulf Coast.
Since the start of the shale Revolution, we have enjoyed only a handful of periods one ample export capacity has been available look.
Looking forward plentiful dock capacity will allow us to fully access the international markets on a sustained basis risk.
Resulting in U.S. Mont Belvieu prices closely linked to international markets.
While antero has enjoyed unrestricted access to these international markets through our Mariner east commitment for nearly two years now this fundamental change on the U.S. Gulf Coast will benefit Antero share of NGL production that is sold domestically and linked to Mont Belvieu pricing.
Turning to slide number eight titled NGL price recovery.
We can see that the strength of NGL markets relative to W.T.I. MBR. Brent has continued to stay elevated as a result of resilient petrochemical and residential commercial markets. During this pandemic here.
Here, we illustrate the outperformance of Mont Belvieu C plus pricing relative to WT I in 2020.
On the right we see the continued outperformance in propane relative to Brent at the far East Index, RFP, I, which is the benchmark in Asia.
What we've witnessed is that demand for LPG in key Asian markets. During the third quarter is actually increased year over year and at the strength of Ngls witnessed early in the pandemic was not temporary.
Looking beyond the resilient residential and commercial demand the relative preference of gap gasoline in the global transportation fuels market. During this pandemic has also been favorable for NGL pricing on a relative basis to oil gasoline.
Gasoline has been less affected than distillates, which has seen inventories increased significantly due to the more pronounced and prolonged decline in global jet fuel demand.
Resulting weak distillate demand has led to reduced refinery runs in the U.S. and globally, which in turn has lowered the production of refinery LPG and other gasoline blend components such as NAFTA.
Ultimately these downstream trends have been either even further supportive of blending butanes and C plus into the gasoline pool.
In addition, the relative tighter supply and demand dynamics for NASA has a knock on effect for LPG as there is some competition between naphtha and LPG as a feedstock in select steam crackers in Europe and in Asia.
Overall, we believe the global market dynamics are constructive for NGL prices at a minimum in the near to mid term timeframe.
Turning to slide number nine titled NGL pricing outlook, but.
The chart illustrates the value that some third party analytical teams, including the Citibank commodities team shown here continue to place on Ngls and 2021 and beyond based on their bottoms up global supply and demand models.
In many of these forecast as the realization that if oil was to stay range bound throughout 2021 at 35 to $45 a barrel the world will simply not be able to supply enough hydrocarbons in the subsequent years to meet demand in a post pandemic environment, which undoubtedly will result in higher prices.
Looking more closely at the northeast takeaway capacity slide number 10 title northeast LPG supply and demand highlights the reason for a tightening of the northeast differentials to Mont Belvieu for LPG that has resulted from the Mariner East project.
Realized northeast differentials continued to improve year over year with more and more volume shipping out of the basin on the Mariner East system as energy transfer has added incremental capacity since initially, placing mariner east two in service.
The northeast LPG supply potentially at its peak here in 2020, we ultimately expect northeast differentials to Mont Belvieu to strengthen even further in coming years with that I will turn it over to Glen.
Yes.
Thank you Dave.
The bullish NGL price outlook is very encouraging for antero due to our position as the second largest NGL producer in the U.S. producing 146000 barrels a day of C plus in the third quarter at that production level at $5 per barrel change or 12 cents per gallon.
In C plus pricing has a 225 million dollar impact on our cash flow. So we have significant pricing leverage there.
Continuing on the macro theme shown on slide 11, we are also encouraged by the natural gas outlook for the fourth quarter of 2020 and into next year. Following the dramatic decline in industry rig counts and completion spreads.
2020 natural gas production is forecast to exit approximately six Bcf a day lower than 2019 in the 86 to 87 Bcf a day range in the US. This reduced activity is expected to extend supply declines into 2021 with production seven Bcf a day.
Below the 2019 peak.
On the demand side, we saw an impact from the global pandemic. This past summer, but primarily through canceled LNG cargoes as us residential and commercial demand remains robust driven by above average temperatures zero LNG cargo cancelations or forecast for this December increase.
Seeing us export volumes at year end, two above pre pandemic levels to over 10 Bcf a day from about nine Bcf a day today.
This demand recovery combined with the stubbornly flat to down supply forecast is expected to lead to an undersupplied gas market in 2021.
Slide number 12.
But the top section of the page highlights the sharp 68% decline in horizontal rig counts in the oil focus basins, the Permian Eagleford Bakken Scoop stack and the DJ.
On slide number 13, you can see the 62% decline in total Qs completion spreads also in the oil focused basis.
This dramatic reduction in activity is expected to result in further declines in natural gas and NGL supplies as we exit 2020 and move into 2021.
Note that 64% of U.S. NGL supply comes from those shale oil basis compared to only 44% of natural gas.
This indicates that the dramatic slowdown in activity in the oil focus shale basins will have an even larger impact on the NGL supply than it does on natural gas supply.
These are some of the fundamentals behind the NGL slides that Dave has discussed.
Slide number 14 title liquidity outlook illustrates our expected year end 2020 liquidity of almost $1.4 billion circle in Red we.
We continue to be proactive with debt repurchases during the third quarter.
Repurchasing $461 million of notional debt at a 13% weighted average discount, including our tender offer that closed in September.
Since the start of our debt repurchase program in the fourth quarter of 2019, we have repurchased $1.3 billion notional debt at a 17% weighted average discount.
Thereby reducing total debt by $220 million from the discount alone, while reducing annual interest expense by $34 million.
The remaining market value of the 2021 and 2022 senior notes net of what has been repurchased today is shown on the right hand side of this slide and totals $915 billion in market value.
Hey, art had almost $1.1 billion of liquidity as of September Thirtyth, which is shown on the dark Green bar on the left hand side of the page.
During the third quarter, we generated $272 million of EBITDAX and free cash flow of $88 million before working capital investments.
EBITDAX of free cash flow numbers exclude the $29 million hedge monetization, which we treat it as an asset sale.
We continue to expect to generate $175 million to $200 million of free cash flow in total during the second half of 2020 based on today's strip prices, providing additional liquidity to reduce debt.
Including the overriding royalty contingent payment of $51 million, which we will receive in the fourth quarter for hitting volume thresholds in the third quarter. This year, we will have $1.4 billion liquidity at year end 2020 more than sufficient to handle both the 2021 and 2022 maturities.
Which once again have a total market value of $950 million today finally.
Finally total debt has been introduced to under $3.2 billion, we expect that to go down to $3 billion by year end due to the free cash flow and debt to LTM EBITDAX was 3.2 times at quarter end.
Next I'd like to highlight our annual corporate sustainability report that was published in October The report highlights our outstanding environmental social and governance or ESG performance, which is shown in slide number 15.
Since our inception Antero has been committed to safety and environmental excellence.
We have a safety record that robot that rivals the majors and have one of the lowest greenhouse gas intensity metrics in the industry.
Our methane leak loss rate of <unk>, 0.046% and 2019 was significantly below the one future industry and sector targets of 1% and 0.28% respectively.
Looking forward, we believe natural gas will be key to the energy transition in the coming decades as a complement to the renewable energy as one of the largest natural gas producers in the US we are well positioned to maintain our peer leading PSG position and be a gas supplier of choice.
Accordingly, we set 2025 environmental targets that include a 50% reduction in our already low methane leak loss rate, a 10% reduction in GHG intensity alignment with Tcfe, the SaaS be reporting guidelines and endeavoring to achieve net zero carbon emissions through operations.
Improvements in carbon offsets.
In conclusion, the Antero team has delivered exceptional execution over the last 12 months slide number 16 titled tremendous execution through the downturn highlights the progress we have made this year.
Despite a challenging backdrop, we have executed our asset sale and refinancing plan raising over $1 billion reduced total debt by $620 million address our 2021, and 2022 maturities lowered well cost by 17%, which supports a low maintenance capital budget of just 589.
$1 for 2021 transition to a free cash flow model and bolstered bolstered our peer leading focus on EPS chief.
These achievements during a truly historic challenges is a true testament to the dedication.
Ventura as employees and finally, it's nice to have some tailwinds with the 2021 natural gas strip up 25% and C plus Ngls up 67% since the April trough.
With that I will now turn the call over to the operator for Q and a.
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Our first question today comes from Neal Dingmann of Truest Securities. Please proceed with your question.
Moving on to Apollo. Good. My question is just on the debt repayment, which I'll consider further dts or further asset sales or would you even go as far as consider given your massive acreage you're drilling partnerships or other strategies to maintain the lower spending in or even pay down debt further.
Yes, we certainly would consider all those are all still on the on the table I think we can be more choosy now.
The commodity price has moved both natural gas and Ngls as we as we forecast we're pretty happy about that so then we generate quite a bit more free cash flow and we can work our way down in that fashion. So we'll be very choosy, and we may or may not do further asset sales kind of depending on how commodity tried prices play.
Adam how the markets behave so.
Certain at this point, but we certainly keep our eye on all those situations as you mentioned.
Okay, and then just one follow up given just wondering given the large amount of hedges youll have some nice hedges, yes, Im just wondering what you will consider ramping activity next year gas prices remained strong like this in order to.
Take advantage of these higher prices or would that would the higher prices change your kind of grow through that strategy next year at all.
Thank you.
We're completely focused on generating free cash flow, so I would expect us to announce.
This has not been board approved yet, but maintenance level capital for next year and maximize maximize free cash flow to reduce that leverage our plan over the longer term is to reduce our debt by at least another $1 billion and get it down under $2 billion total debt and leverage appropriately down under under two.
Yes.
No that makes sense. Thank you. Thank.
Thank you. Thank you.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
Good morning, Paul Glen Mike team, Thanks for taking my questions.
Yes.
Just curious maybe to just to follow up on NEALS question, there around the growth strategy, you articulated and obviously with the successful re determination on the borrowing base.
Do you have enough liquidity cover absent any other asset sales to retire 21 to 22 maturities.
I guess as we think about maximizing free cash is this you know the district has obviously moved up considerably even above where the hedge book is do we think about just long term reactivating grossing getting back to maybe parity are growing into that firm transport portfolio in this three dollarsish world.
If were beyond this $1 billion debt pay down.
Well Fortunately as we pointed out David the the firm transport pool portfolio grows down to to meet us. If we stayed at maintenance capital So does shrink.
Shrink to well under $100 million of carry on that which is a real benefit over the next few years. So we don't feel compelled to reach up to do that but there may be other ways to to fill that that firm transport over time. So we're just showing you the numbers without any third party gas purchases and their various other ways to do that later.
Transport et cetera, so rather than reacting with the drill bit like we've done in the past I would say the more working the transport portfolio and working that down.
Got it.
So too I guess expand on that a bit.
From transport, you, you're giving notice I guess to release some of the capacity going down to the Gulf Coast.
Talked about how that impacts and helps you on that marketing side.
What do you think that what's the impact I guess and 21 in terms of where the strip is now to your your debts on the gas side and resulting transport expense.
Yeah, there's there would be no impact in terms of we're optimizing here and releasing pieces that are not the most optimal pieces of transport. So we don't see any negative impact on our netbacks. So no concern over that.
The the net marketing expense would be impacted but not the underlying transport expense. So it's at 11 cents per mcf fee that we.
We had in the third quarter that gets impacted overtime right.
All right. So I guess for for what you're going to be selling of your operated gas produced guess, you're just you're keeping the same sort of pro rata exposure.
That's right yes.
Okay.
Big book, It's big scale back to the earlier question.
You know, we don't have a real need to to grow volumes right with being.
Being the third largest gas producer second largest NGL producer were not strongly compelled by that today, it's really more about.
Extracting the most cash flow can from the food business and repaying debt.
Got it and if I could just add one quick quick on here. This next year I know there is an assumption of of the shell cracker start up at some point around mid year, obviously, that's a decent uplift your ethane volumes.
What do you what do you seeing today it looks like the crackers almost near completion in the pipeline there is effectively complete.
When do you think you're going to start seeing first volumes kind of extracted there.
Yes, good question David.
Shall I think recently.
But put out some information that they were about 70% complete on the facility here probably in the last month or two so so a lot of progress made but still it's still a ways to go if you look back at their second quarter earnings slides, we had in the appendix kind of a reference of that project now being 2022, plus and that that bucket of projects that they have so.
We're not expecting it at all next year.
Certainly 2022 is in the realm of possibility but.
Phil still a ways to go on the project there for them during a challenging.
Construction environment.
But for US, it's a significant ramp up in our ethane volumes and we're excited about the project and what it means for the for the region, but the overall impact on on anteros not tremendously material. So.
Got it thank you guys.
Thank you.
The next question is from US we bought Sciandra Guggenheim Partners. Please proceed with your question.
Hi, guys. Thank you.
So the I guess the value of ft improving.
Do you see opportunities or demand for some of that excess ft that might have us take down our net marketing expense next year.
Hi, Subash.
Yeah, there's there's definitely demand there is distressed gas in the M to pool in Appalachia and so.
Every day, we are buying.
Pretty large volume of third party gas and moving it to our pipe and collecting the spread to places like Chicago and the golf and so that helps to reduce our net marketing expense by by buying and selling at a premium that third party gas the distressed third party gas in the.
I am too pool.
The way things are shaping up we see that those wide basis differentials continuing to Cal 21, and so the opportunity is there for us and we are seeing that basis blow out so yes.
Yes, I think we'll continue to see that in terms of releasing empty it can become a it's.
It's not as straightforward as just buying that third party gas and putting into the pipe. We we have our feelers out we sometimes release seven of RFP seasonally.
For example.
Releasing for five months during the winter and and collecting much of the demand charge to offset our our unutilized ft, and reducing that net marketing expense. So other ways to do it and we do it here and there and many of our pipes, but.
Straightforward way is buying the third party gas.
Got it Okay, and then on well costs I guess we've.
We've been talking quite a bit about.
GAAP and so on when do you think you get comfortable with either going with regional sand or not and could you just give a sense maybe of Intel.
In terms of magnitude what that could do to well costs. If you. If you were to adopt that on a wide scale basis.
Yes, so you know to to make the distinction where we've moved away from this so called northern White from Wisconsin et cetera, and so.
Much of our sand is the equivalent of the geologic equivalent of the northern White, but is from Missouri, and so we use mostly that from a different sand suppliers. Its barge right up to a trans load next to our acreage so that saved quite a bit of money, we continue to work things down.
And work our cost structure down.
What kind of mean in well costs, well time will tell could save $100000 could save $200000 or more as a.
As prices get lower with the with the competition so that would be.
20, $30 per foot that we could still reduce beyond where we are now.
Okay terrific and if I could just assets because you have your NGL expert on the call.
I'm just curious when I'm looking at global LPG.
Prices have come in a little bit here recently, how do you bracket sort of sensitivity to second wave Ur cobot et cetera, and how.
How much lower do you think prices could go from an export.
Yes.
Yes, great question.
It's a bit of a.
Two pronged.
Answer here I mean, the first the first pieces if there is a second pronounced wave.
Similar to what we saw back in the spring. The most immediate response is a reduction in ER and refinery runs just a lack of transportation fuel demand and so what we're seeing refineries here in the U.S. still running in the low 70% utilization rate and globally.
Similar a similar pressure and so if that goes lower at that actually could create a situation where LPG supply is reduced during a time of the year, where whereas calm demand really isn't expected to be all that affected by a second wave in fact, you're starting to see expectations here in the U.S. with one more folks working at home that you could actually have a yeah.
Roughly 5% increase in RASK on demand for for propane for.
For home here, so you'll see that around the world and that's that's the potential upside to it but.
You know it also does.
See propane and butane trade relative to the oil and yeah. We saw back in and start of the pandemic propane trading at 140% of oil that's not to a level that can be sustained probably for enable great period of time, but just kind of highlights how are the pricing can decouple, so tough to say what will happen in the second way.
Dave.
We think relative to the heavier hydrocarbons Ngls will will perform significantly better but.
Ultimately none of us want to see won't want to see the demand destruction that does come from a second wave across the board for all commodities.
Got it.
Thank you.
Thanks, Josh.
The next question is from Harry haul back of Raymond James. Please proceed with your question.
Hi, guys youre around that 70% gas mix for 2019, and it's kind of come down every quarter to around 65%. This quarter. I was just curious where do you see that going moving forward is that mainly just a consequence of where you're drilling or is it some sort of color on commodity prices going forward.
You know, it's where we're drilling drilling but it is it is a bit of a call on commodity prices, we feel really good about NGL prices as we've mentioned earlier and natural gas to so.
For us the best economics in that kind of bullish bullish scenario.
The drill our liquids rich acreage and I think if we stay on that course over the next few years that we do mix in some dry gas drilling here and there, but if we stay on that towards I think the percent gas could drop to as low as 60%, but that's that's probably the the outside.
All right. Thank you for that and then you know I was also just kind of wondering obviously consolidation it hit the energy space and most of that is focused on the Permian, but there has been a few deals.
He and even southwest in Appalachian I was just wondering you won't see any value for inherent pursuing M&A at this time.
Well, we certainly keep our eyes on it all the time, it's been good to see I think it is productive and for the industry has been predicted for a long time I.
I do think we'll see more in that in Appalachia. So it's something that we monitor whether we will participate.
I don't know at this point, but.
It is very interesting the development.
All right. Thank you for that congrats on a great quarter guys.
Thank you. Thank you.
The next question is from Gregg Brody of Bank of America. Please proceed with your question.
Good morning, guys.
Greg Greg.
Just just.
But just trying to reconcile production cadence for this year I'm just taking into account the baby.
Pp and the and the market the transaction is your.
The 2020 production number that we're supposed to think fight on is that 3.45 or is it 3.5 Bcf per day.
30.4, or five it that's net of the WGP is treated as a divestiture. So it's not included in the volume so.
You take the three five original and subtract the 50 million a day from the VPP.
And.
As we think about this fourth quarter. It was was third quarter greater because you processed more more ethane or is it that we should expect the fourth quarter to decline to meet that number.
No and nothing to do with that during the third quarter with better just because the well results and the development plan exceeding expectations.
I have got this question on the guidance.
We don't adjust our guidance for one or 2% in.
Increase or you know that's kind of rounding when you deal with these kind of large numbers.
That can kind of result, especially when there's only one quarter left with.
Unreasonable thoughts around production in the fourth quarter, but just a rounding alone you know coming one to 200 million a day for fourth quarter, when you're talking about 3.5 Bcf a day so.
Just on adjust our guidance, one or 2% not material.
Got it that we should be thinking about keeping production flat next year at 3.45.
Correct.
Got it.
Congrats on the borrowing base Redetermination that's great.
You know once you have a success. It is you have a momentum you ask what's next so I'm kinda ask [laughter].
Just curious how you're thinking about the next redetermination.
If what sort of what some of your hedges rolling off is or do you do you expect it to be the same.
Well, it's one day old [laughter], but the you know the commodity prices are higher than where we actually started this redetermination. So I would actually expect those prices go higher in the spring. So I would expect our borrowing base be higher as well our borrowing base actually calculated.
Well in excess of $2.85 billion.
If you don't and today thanks.
Markets, you don't really asked for an increase but our borrowing base is well ahead of the two a five so I don't see any issues there.
Got it and.
And then you you touched on the asset monetization and possibility.
Curious.
How do you think about additional converts or common equity markets for de leveraging.
Yes, I think as I said earlier I Greg.
Well I didn't say, we want to be patient, but we've been patient and thats really paid big dividends to be that way and not to not rush to exit this or that and so I.
I think we'll continue to.
Look at the asset markets and if we see real good value, we'll do something but otherwise.
We really do feel like the the wind at our back a bit here with commodity prices moving as they are it's a volatile time, you know where we see some downturn because of the second wave third wave whatever.
We could but right now it's looking pretty good and we're just enjoying enjoy those tailwinds and we'll be paying down debt with that Oh.
Overtime, so don't see any dramatic moves, but you never know if we see some real value somewhere that will take advantage of that.
Great and last question for you.
So.
You gave some good color on the NGL market, just trying to think about how to think about ethane.
Since going forward and maybe some goalpost as to how you think about it.
Yeah, most of the the ethane in the basin, that's going to be be consumed.
Within region, and there's really I would say, there's four existing petrochemical users to up in in Ontario, one down in not in Calvert City, Kentucky and then.
Honestly the shell project Thats.
Talked about earlier.
Most of those transactions I think you're going to see producers.
Basing those deals on a gas based index, so they're going to be some.
Some kind of uplift relative to natural gas economics for producers in the region. There is going to continue to be really through the end of this decade. The atex pipeline that flows down to Mont belvieu and so that without a doubt its going to be Mont belvieu linked and so there'll be a.
I would say an increasing percentage of gas linked portfolio deals for the for the basin and for producers like Antero as some of these expansions and new projects come online for our.
Local and regional consumption and.
Then the Baytex exposure is kind of a base load thats fits Mont belvieu linked.
Got it thank you very much.
Thanks, Craig.
There are no additional questions at this time I would like to turn the call back to Michael Kennedy for closing remarks.
I want to thank everyone for participating in our conference call today.
Any further questions. Please feel free to reach out to us. Thanks again have a good day.
This concludes today's conference you may disconnect your lines at this time. Thank you for your participation.
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Okay.
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