Thank you for joining us for Antero’s fourth quarter 2020 investor conference call. We'll spend a few minutes going through to the financial and operational highlights, and then we'll open it up for Q&A.

But also I like to direct you to the homepage of our website at www.anteroresources.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 to a number of risks and uncertainties, many of which are beyond Antero's 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.

Joining me on the call today are Paul Rady, Chairman and CEO; Glen Warren, President and CFO; and Dave Cannelongo, Vice President of Liquids Marketing and Transportation. I will now turn the call over to Paul.

Thank you, Mike. Let's begin on Slide Number 3, by discussing the formation of the drilling partnership that we announced this morning.

Under the agreement QL Capital, an affiliate of Quantum Energy Partners, will fund 20% of drilling and completion capital in 2021; and between 15% and 20% of total drilling and completion capital in 2022 through 2024 in exchange for a proportionate working interest percentage in each wells spud. QL will participate in every well that Antero drills over the next four years, starting with wells that were spud as of January 1, this year.

So as of about seven weeks ago. As you can see on the lower right side of the slide, we will drill and complete over 300 wells over the next four years together.

The result is an incremental 60 gross wells being drilled through 2024 as compared to our initial base development plan. Importantly, on a net basis, AR's net capital spending and production will remain unchanged from our prior maintenance capital programs.

Slide Number 4 illustrates how Antero is in a unique position to benefit from a drilling partnership. First, we have over 2,000 premium, undeveloped, core drilling locations in the Marcellus and Ohio Utica, and a contiguous acreage footprint that delivers efficient development.

I'll discuss our advantaged drilling inventory in more depth, a little later in the presentation. Second, since over 1,400 of Antero’s 2000 plus premium undeveloped core locations are liquids rich, we are well-positioned to take advantage of the strong NGL prices that Dave Cannelongo will talk about in just a minute.

Based on our recent basin-wide study of the remaining undeveloped locations in Appalachia, we estimate that these 1,400 AR locations represent approximately 38% of the remaining liquids rich core locations in Appalachia. Third, we have unutilized firm transportation to premium markets that supports the incremental gross gas production from this drilling partnership.

This allows Antero and our partner to deliver gas to NYMEX based indices, unlike many northeast producers that don't have firm transportation to cover all of their production. And so, they experience frequent basis blow outs, and often have to shut in supply due to low northeast gas prices.

Lastly, incremental production from the drilling partnership will allow AR to capture additional fee rebates from our already established low pressure gathering incentive program with Antero Midstream. These factors, all of which are unique to AR, drive the substantial increase in our free cash flow profile over the next several years, as detailed on Slide Number 5, titled free cashflow enhancement.

As depicted by the red box on the left-hand side of the page, the drilling partnership allows Antero to fill unutilized premium firm transportation and reduce net marketing expenses by approximately $260 million over the next five years. This benefit really starts to kick in, in 2022 as we put to sales, the incremental wells drilled in our 2021 tranche of the drilling partnership.

The incremental production from the drilling partnership also allows us to capture $75 million of additional midstream fee incentives. We are estimating $50 million of drilling carry under the drilling partnership based on strip pricing and interest expense savings of $20 million.

And finally, most of the $400 million of free cashflow derived from the drilling partnership is not very sensitive to natural gas and NGL prices. Slide Number 6, titled partner production fills AR's unutilized AT highlights Antero’s gross volume forecast under the drilling partnership as compared to base plan volumes.

As you can see with the drilling partnership, we now expect to fill our premium long-haul transportation by 2023. Slide Number 7, titled growth incentive program, summarizes the gathering fee rebate thresholds that were previously established with Antero Midstream.

The incremental gross volumes generated by the partnership should result in AR achieving additional LP gathering earn-outs totaling $76 million, possibly more. Lastly, we estimate that we will receive a delayed carry on the drilling partnership in the form of one-time payments per tranche, one year after the tranche is drilled that total approximately $50 million by achieving certain IRR thresholds.

Now, let's turn to Slide Number 8, titled enhanced free cashflow profile. In total of the drilling partnership is expected to increase AR's free cashflow by $400 million, compared to our base plan.

This equates to over $1.5 billion of free cashflow through 2025 based on today's strip prices. This increase in free cashflow results in a substantially lower leverage profile from 3.1 times today to under two times this year.

Remember, this free cashflow profile is based on a backward-dated strip price. If 2021 strip prices held flat through 2025, we would expect Antero to generate $3.5 billion in free cash flow.

That is $2.90 gas and $35 per barrel C3+ NGLs. Now let's discuss the drilling inventory in the Appalachian Basin.

Slide Number 9, titled peer leading premium core inventory, provides a summary of the core inventory remaining in the Appalachian Basin as we see it. We recently completed our annual, detailed technical review of peer acreage positions, undrilled acreage and location potential.

This technical review also analyzes BTU, well performance and EURs. The results led us to bifurcate the cores of the Southwest Marcellus and the Ohio Utica into premium and Tier 2 sub areas.

We've identified approximately 5,200 premium, undeveloped locations in the Southwest Marcellus, which are located within the red outlines on the map. Of that, we estimate Antero holds 1,865 of those premium locations, or 36% of the total.

In the Ohio Utica we estimate roughly 1,100 premium undeveloped locations of which Antero holds 210 or 19% of the total. Beyond that we estimate that there are 1,600 Tier 2 locations remaining, which you can see are located within the blue lines.

You can see much of the acreage is covered up with existing Marcellus and Utica production, horizontal wells, which are the red lines on the map. Antero’s extensive undeveloped premium drilling inventory made a drilling partnership, highly accretive to our development plan with only 60 incremental locations committed to the partnership.

Ultimately, we believe that so-called inventory fatigue and the limited number of premium drilling locations will be a critical distinction between the haves and have nots across Appalachia producers. I’d also like to thank the Antero Land, GIS, geology and reservoir engineering teams for all of the time and effort that went into delivering this rigorous technical analysis.

Our people have always done an exceptional job providing basin and peer level details that are critical to our strategic decision making process. This analysis leaves us even more optimistic about Antero’s competitive advantages as we look towards the future.

With that, I'll turn it over to our Vice President of Liquids, Marketing and Transportation, Dave Cannelongo for his comments. Dave?

Thanks, Paul. Let's begin by discussing the NGL and LPG markets this winter.

For the last several quarters, we have talked about the imbalance in supply and demand in the LPG market underpinned by strong international demand for LPG in the residential, commercial and petrochemical markets and lower supply from U.S. shale, OPEC and refinery runs.

Despite entering the winter with near record propane inventory levels on an absolute barrels basis, a lackluster U.S. crop drying season and mild early winter.

Due to LPG exports, we saw U.S. propane inventory levels experience a record setting rate of withdrawal as illustrated in Slide number 10, titled propane market fundamentals.

On the left-hand side of the slide, you can see absolute propane inventories that went from the high end of the five-year range only a few months ago to the bottom of the five-year range today. On a days of supply basis, new record lows have also been reached in recent weeks of just 15 days of supply as illustrated on the right hand side of the slide, which is 34% below the five-year average.

The addition of LPG export capacity in late 2020 as illustrated on Slide number 11 titled material impact to NGL production in the U.S. allow the U.S.

to export record levels of LPG to meet this demand, quickly drawing inventory levels here. As propane inventory levels plummeted in the U.S.

with winter not yet over in the coldest temps of the year yet to come, prices for LPG in Mont Belvieu, Texas responded in an attempt to slow down the export flow and preserve inventories for domestic res com winter needs. The result was that propane went from trading in the low $0.50 per gallon level in November to as high as $0.98 per gallon in January.

Prices have since stabilized in the $0.90 per gallon level. So the effects of the recent extreme U.S.

coal are still playing out as we speak and trading above $1 per gallon this morning. Antero’s C3+ pricing has risen from $27 per barrel in the fourth quarter of 2020 to over $39 per barrel today.

You can see that pricing detail in the appendix of this presentation. While this was occurring, the numerous analytical teams that had predicted higher oil prices in 2021 saw their thesis come true though perhaps earlier than expected.

Higher underlying oil prices and low U.S. propane inventory levels together resulted in a steady increase in C3+ NGL prices as you can see on Slide number 12.

Looking forward, we believe upside remains for the LPG forward curves, especially given the lack of Contango in the structure headed into the next winter. Demand for LPG continues to steadily grow for global res com use as adoption of LPG as a cleaner and healthier burning fuel for cooking and heating is embraced.

Additionally, there are numerous new build petrochemical projects coming online this year and next that will strengthen the poll on waterborne LPG to Asia. China alone is adding over 350,000 barrels per day of petrochemical LPG demand from 2020 to 2022.

We believe that LPG production will need to come back online through both increasing refinery runs, OPEC and growth in U.S. shale to keep pace with this resilient and growing global LPG need.

Turning to Slide number 13 titled Northeast LPG Supply and Demand, we continue to see improving realizations and NGL sold domestically. Mariner East continues to deliver as a world-class asset, one that has been critical to supply and global LPG needs.

With recent changes to the Panama Canal booking procedures favoring LNG carriers, and dry goods container ships beginning in 2021, more LPG carriers will likely be sailing around the Cape of Good Hope from the U.S. to reach Asia.

With these changes, energy transfers, Marcus Hook industrial complex, where Antero markets its export product is one of the facilities, anchor shippers will now enjoy a shipping advantage to both Europe and Asia. While ample of U.S.

export capacity has resulted in lower dock premiums to Mont Belvieu. The overall effect of a de-bottleneck U.S.

market on Antero has proved positive resulting in stronger overall C3+ realizations as has been evident in our fourth quarter results in 2021 estimates to date. With that, I will turn it over to Glen.

Thank you, Dave. Good morning.

A bullish NGL price outlook is very encouraging for Antero due our position as the second largest NGL producer in the U.S., producing 132,000 barrels a day of C3+ in the fourth quarter last year. At that production level, every $2 per barrel or $0.05 per gallon change in C3+ pricing as a $97 million impact on cash flow.

You can see that lower right on Slide number 14. A key catalyst to Antero self-driven plan to number one, address near-term maturities, and number two, fill our premium FT in a flat production environment has been a series of creative financings.

As highlighted on Slide number 15, over the past year, we've raised over $1.1 billion of committed funds through an overriding royalty transaction, a volumetric production payment, and a drilling partnership with three outstanding counterparties, all leaders in their respective spaces. Those are 63 Capital [ph] Partners, JPMorgan, and Quantum Energy Partners.

We truly appreciate their strong endorsement of our assets, operations and company. Now let's turn to Slide number 16, entitled Much Improved Senior Note Term Structure.

In late 2019, we announced a de-leveraging program with a goal of addressing our near-term maturities. Since then, we have eliminated $2.3 billion of near-term maturities and reduced absolute debt by over $800 million.

As you can see in the maturity schedule at the bottom of the slide, we now have just $574 million due over the next four years, a dramatic improvement from the nearly $2.9 billion we had due over that timeframe at the beginning of the program. Slide number 17 titled Significant Leverage Reduction and it illustrates how the recent financing transactions combined with expected free cash flow have and will dramatically reduce borrowings under our credit facility and improve our leverage profile.

The dark green bar on the left hand side of the slide is our credit facility balance at year end 2020. Accounting for the net proceeds from our two recent senior note offerings that's net of the – the bond redemptions between 2022s, which totaled $525 million after calling the 2022 notes, the convertible senior notes, equitization and the $51 million contingency payment related to royalty sale and our 2021 projected free cash flow of at least $500 million, we expect to have almost nothing drawn on our credit facility at year end 2021.

You can see that as you move across the page from left to right. This is impressive reduction in our credit facility balance, and it results in our leverage ratio declining from 3.1 times at year end last year to below two times this year.

Strengthening our balance sheet was a top priority in 2020, and we are extremely proud of the significant progress we have made in a short period of time. Now I'd like to briefly touch on some financial and operational highlights for the quarter.

Adjusted EBITDAX for the fourth quarter was $299 million, a slight increase from the year ago period has lower operating costs and increased production offset, lower realized prices and realized hedge gains. Our realized natural gas price after hedges averaged $2.76 per MCF, representing $0.10 per MCF premium to NYMEX.

C3+ NGL price was $27.64 per barrel for the quarter. As Dave mentioned, that's running at about $39 a barrel today.

That was $0.84 per barrel premium to Mont Belvieu pricing and 26% increase from the prior quarter as we've benefited from premium international prices. And finally free cash flow during the quarters was $155 million.

On the operations front, we placed 11 horizontal Marcellus wells to sales during the fourth quarter that had an average lateral length of 15,788 feet. 10 of these wells that had 60 days of initial production set a new company record averaging 33.9 million cubic feet equivalent per day over 60 days.

2021 will also be an exciting year for Antero’s ESG initiatives as we look to build our – on our peer leading sustainability and ESG metrics. Slide number 18 highlights the environmental goals that were announced in 2020.

These goals include a 50% reduction in our already low 0.046% methane leak loss rate, a 10% reduction in GHG intensity alignment with TCFD and SASB reporting guidelines and endeavoring to achieve net zero carbon emissions through operational improvements and carbon offsets. Looking toward the future, we believe natural gas will be key to the energy transition in the coming decades as a complement to renewable energy.

As one of the largest natural gas producers in the U.S., we are well-positioned to maintain our peer-leading ESG position and be a gas supplier of choice. We are active members of the American Exploration Production Council, or AXPC, which early this month announced ESG framework with a goal of creating uniform reporting standards.

We believe this is an important step toward addressing key investor concerns around consistency and comparability of ESG reporting. In conclusion, the Antero team has delivered exceptional execution over the last 12 months.

Slide number 19 titled Key Investment Highlights summarizes the position of strength we're in today following the execution. We have significant scale as the third largest natural gas producer and second largest NGL producer providing attractive exposure to strengthening commodity prices.

The drilling partnership we announced today incrementally boost our free cash flow profile by $400 million over the next five years and to over $1.5 billion in total over the next five years, including that $400 million based on today's strip prices. As Paul mentioned that $3.5 billion over the five years at 2021 strip held flat that's 2.9 in gas and $35 C3+ NGLs larger – that's larger than our current market cap.

So I mean, the cash flow potential here is outstanding. Since the beginning of our development program, we've reduced total debt by $800 million issued $1.5 billion of new senior notes and redeemed our 2021 and 2022 maturities.

This leaves just $574 million senior note maturities through 2024 and these can easily be addressed with our projected liquidity of $1.9 billion at the end of this year. Further we expect to achieve our leverage target of under two times this year.

These achievements while our industry and the world faced truly historic challenges is a testament to the dedication of Antero’s employees. With that, I will now turn the call over to the operator for questions.

Yes, good morning, gentlemen. I guess the first question is if you could provide a little bit more color around the 2021 liquids guide relative to 2020, it looks like the mix is going down from 33% to 31%.

And perhaps you give us a bit more color around the accounting for the royalty barrels and how that's affecting your C3+ volume guide for 2021?

Yes, Arun. Hi, this is Mike Kennedy.

We elect obviously not to pay our royalty owners and uneconomic NGLs. So in 2020 obviously with the liquids prices, the averages those were uneconomic to process.

So we did not pass that along to our royalty owners with the increase in commodity prices and liquids prices in 2021 that will not be the case. So what occurred in 2020 is we allocated all of the liquids from the wells to Antero and paid our royalty owners and natural gas volumes in 2021.

We now will pay the royalty owners and their share of the liquids and have lower royalty payments from a gas perspective. So, it's actually a huge benefit to Antero from a cash flow standpoint.

When you look at 2020, we allocated ourselves about a $50 million negative cash flow amount related to processing on economic NGLs and retaining them for our own account versus allocating them to royalty owners in 2021 that reverses. And so, we'll have a little bit higher realizations because of that and lower processing costs, but also a little bit lower net production.

Got it. Got it.

And that's helpful. And just a follow-up is, can you provide a little bit more color around the potential marketing uplift in 1Q, given the conditions in Texas and Mid-Continent, we did note that you did raise your natural gas realization guidance for the full year, but maybe help us to understand what kind of uplift you could see given the pricing surge that we're seeing on our screens?

Yes, yes. We did up our guidance on that without the recent winter weather then it would have been flat to $0.10 premium with our initial guidance.

Over the last week, we've been able to track some of our gaps where it's needed most and that enabled us to capture about an incremental $75 million of revenue, $50 million of that will be realizations, $25 million will be in lower marketing expense. So we did adjust our realized guidance for that $50 million.

So that's why we increased it from flat to $0.10 to now it's $0.10 to $0.20. And you'll see the majority of that increase occurred in the first quarter.

Okay. But that's just booking what you've realized thus far.

So is that potential for that to get larger…

Correct.

Okay. Thanks a lot, Michael.

Thanks Arun.

Yes. Hi.

Good morning, everybody. On the four-year outlook that you have, it looks like the CapEx is around 635 a foot.

I think you're going to be there this year, second half of this year. Can you just talk about maybe how conservative that outlook might be over the four-year period?

Yes, I think it's probably on the conservative side, Subash. We have a couple of key drivers that take it down this year from 675 as we finished last year down to that 635.

And there's some initiatives on the sand side as well as completion side. So we feel pretty confident in that.

Can we take it even further, even lower? I think there's still upside there.

We generally don't like to talk about anything that we don't have pretty well under control in hand. So that's what we're talking about here is what's in hand and beyond that there are some other things that we continue to work on.

So that's definitely the potential. And in terms of the service costs these days, we still see sort of downward pressure in general on service costs kind of in the $5 to $10 a foot range.

So we don't see that turning around just yet.

Okay, thanks. And as a follow-up, can you sort of give us a picture on how NGL volumes shaping up this quarter?

And if sort of that export split is looking similar to Q4 or has there been any sort of weather disruptions or even an ability to split more and export more in the first quarter?

Yes, I should include in my first comments. The gross wellhead volumes is flat year-over-year and it is truly a maintenance capital volumes.

Obviously, you had elevated volumes in the third and fourth quarter as we had a gross capital in the first half. So the NGL volumes in the first quarter will be down similar to what the guidance is because of a lack of completions in the fourth quarter, but also because all of the economics are clearly economic at $40 per barrel.

There have been no disruptions. There'll be the same mix between export and selling at the Hopedale.

Okay. Thanks, guys.

Thanks, Subash.

Hi, all. Thanks for taking my question.

So I wanted to get into your FT commitment into a little bit with the new drilling partnership. So I know you get into this on Slide 6, I think.

But I wanted to talk how things have changed versus your previous expectations. So I know you had previously talked about the potential for FT volumes to decline by 810 MMcf a day with about 300 of those rolling off this year.

So I'm just wondering if you can give an update on how we should think about that FT roll off, what annual fees it may look like and any comments you can provide on that marketing expense based on this new drilling partnership.

Yes. That all still holds.

It all does roll off still. So you can see that on that slide, how you're in the – around the 4.147 BBtu per day, going down to 3.130 by 2025 now.

The difference to drilling JV is a lot of that is now filled by the drilling partnerships. So by the year end 2025, you have no marketing expense.

So you see that in the guide to our guide of $0.08 to $0.10 down from our initial guide, which would have been more in the $0.10 to $0.12 range.

Okay. Very helpful.

And then just a follow-up. So I was hoping for a little more detail on the new CapEx and production guidance versus what you had in your December presentation.

So in that last presentation, I think you had a D&C CapEx of 580 to keep production roughly flat. And now your new CapEx guide is slightly higher at 590 with production dropping by about six points.

And I know you've touched on the liquids portion of that in answering the Arun’s question. But wondering if you can just touch on any drivers to explain that difference, and has anything have changed in your assumptions between December and now beyond the new drilling partnership?

Yes, yes, nothing has really changed. I can't really talk to $10 million of capital, but – in this size of a company.

But when you look at the average for 2020 we are at 3.55 Bcf a day – Bcfe a day that EPA I talked about $150 million. So we're not going to have any sort of allocation of liquids solely at Antero, so that gets you down to 3.4, and then we sold the VPP mid-year July, which is $50 million a day and that gets you the 3.35, which is the midpoint of our guidance.

Okay, great. Thanks very much.

Thank you.

Good morning. Thanks for taking my questions.

My first one is on capital allocation across the portfolio, around the Marcellus, Utica mix that we see this year. Just wondering if that's a good base case, I guess, ratio to think about over the next several years?

And also what the mix between premium and Tier 2 Marcellus looks like within the Marcellus bucket?

Yes, I mean, all of our drilling will be in the premium bucket over that five-year plan. And the mix is roughly 90-10 Marcellus, Utica, I think, it's maybe 88% Marcellus.

And we'll put out a little bit more detail on that in our website presentation, which we rolled out later today. So, you'll see a little bit more detail there, but it's primarily Marcellus-focused with some Utica various part of [ph] the year.

I mean, we plan to drill two Utica wells this year a couple of pads anyway.

Okay. I appreciate it.

And then secondly, apologize if I missed this earlier, but just wanted to confirm that maintenance on a net basis is how we should be thinking about CapEx and production through that same partnership plan timeframe, especially considering the line-of-sight to fully utilizing your long-haul, or if that was specific to 2021 and there might be inflection points from a macro standpoint that would incentivize any sort of activity beyond maintenance?

That's a good question. That's the way we built the plan was off of maintenance capital throughout the five-year outlook that you see on the page there.

So, we're essentially holding maintenance capital around that $590 million, $600 million number. It bounces around a little bit each year, but that's generally the outlook.

And I think over the five years, it actually – we're spending a little bit less than we would have pre drilling partnership and that's excluding the, any kind of carry payment. But it's actually down a little bit, I think, $15 million or so over the five-year plan.

So that's absolutely right. It's a maintenance capital program for AR for the next five years.

That is the plan certainly for now to generate maximum pre-cash flow and paydown our debt profile.

All right. Thank you.

Thank you.

Thanks.

Hi guys. So just a quick question here.

And it really gets to the use of all the free cash flow. So, to the extent that you guys do what appears to be an excess of $500 million of EBITDA in the first quarter, and you have your entire revolver paid off by the end of June, right.

As we think about a $3.5 billion total free cash number, right. How do you plan on or think about allocating that against a market cap as you guys make the point, right, that is less than the full $3.5 billion and a free cashflow yield on an equity that's well over 25% at this point?

Yes, that was a great question. So, I couldn't have said it better myself.

Yes, that's a big number. And once again, that would be holding our gas flat at 2.99 max for the five years.

And there are a lot of views out there on that. Some feel like that it's going to go higher certainly in the next few years and then holding NGLs flat the C3+ at $35 a barrel, that's where you get to that $3.5 billion number.

So easily, I mean, the first use of proceeds is to pay down debt just as you decided, and pay down that credit facility and continue to pay down our debt until we get below $2 billion. And that happens over the next several years, next couple of years, really, depending on your price.

If you hold it flat, that happens probably next year. But that's the first use.

And then, we'll start to segue towards return of capital to shareholders. Could there be some A&D along the way?

That's possible. But it would be eventually to shareholders and in the form of potentially stock buybacks, but also considering dividends at some point, if you'd have that count, free cash flow profile.

So, time will tell. And the nice thing is we have the benefit of looking at it every quarter as we go along and adjusting as we go.

But a good question.

Yes. Okay.

I mean, it would just seem to me that you have an opportunity to effectively almost take yourself private on a free cash flow here, right over sort of a two- to three-year window. And I may be more aggressive on propane prices, but net of $60 oil and the shortage we have, that's one person's opinion, but that's how I'd be thinking about it.

Thank you.

Yes, thank you.

Thanks.

Good morning, gentlemen.

Good morning Holly.

Maybe just a question, I appreciate all the details on Slide 9, on just the inventory in the basin. Glen, I'm curious your thoughts and maybe how does this impact your overall view and thinking on just on M&A?

Yes, thank you, Holly. I appreciate the question.

Yes, I mean, it's obviously – I mean, we're not driven to do M&A for inventory reasons necessarily. I mean, that's well in hand with a couple of thousand premium locations, and even with the drilling partnership, we're churning through about 80 locations a year and they average 13,000 feet in lateral length.

So, these are big wells. And so we've got many, many years of running room in inventory.

So, that's not likely to be a driver for us in M&A, but there are other reasons that you do acquisitions as well, of course. Sort of one of the points is you have a basin just doesn't have that many years of running room premium inventory.

Now that should tell you that eventually you see higher prices, and maybe we're seeing that move even now. But over time, I mean, if you run 30 rigs in the southwest Marcellus and Utica, for instance, I think today we’re 26 or 27 rigs in the Utica and the Southwest Marcellus.

These rigs these days can generally drill 30 wells a year. And so just using an easy math, let's say it's close to a thousand completions a year.

If they are only 5,200 premium Marcellus and 1,100 Utica, that's only about six years of supply in the premium realm in the Southwest. So that's pretty sobering, because that's not been the case for many years and that's the way we see it when we analyze each acreage position out there.

Yes, it seems to point to a lot more activity, not drilling activity, but consolidation activity.

I think you're probably right.

Maybe just one and maybe Mike, this is, more on the micro side of things. As we look at the February natural gas commentary that you provided in the release, we went back and looked, you had one quarter, I think, it was the first quarter of 2018 where you turned that net marketing expense into a $0.27 benefit.

I know you broke out sort of the $50 million, $25 million revenue versus net marketing expense. I mean what does it take to kind of – I guess let's flip the switch and have another quarter like that that 1Q 2018 from a net marketing expense standard?

Yes, that was the polar vortex here in the East coast. So, you are seeing another winter weather event most likely occur this quarter as well.

I mean, the interesting thing about this quarter is, it is still ongoing. It's just a broad impact of this, and we're still seeing premium prices out there.

And who knows what happens from here with storage and all that. So it's going to be an interesting six weeks, I think, the next six weeks.

Yes. And maybe Glenn, just to follow-up to that, do you have like a percentage that you could share on just, I guess, the way I've thought about everybody's portfolio is there's just not a lot to sell in the spot market itself.

Most open volumes are priced at midweek. So, is there anything that you can share to give us kind of a rough ballpark on what you can sell into spot?

Yes, I think it's in that 450 million, 500 million a day range is kind of what we have available depending on pipe capacity and all that to move around the system, whether that's Chicago, Midwest, or Gulf Coast. So, it's a pretty significant number for us.

Wow! Okay, thank you, guys.

Thanks Holly.

I would like to thank everyone for participating in our conference call today. If you have any further questions, please feel free to reach out to us.

Thanks again,