Greetings, and welcome to the Antero Resources 4th Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. And as a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Michael Kennedy, Senior Vice President of Finance.
Thank you, sir. You may begin.
Thank you for joining us for Antero's Q4 2020 investor conference call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q and A. I'd also like to direct you to the homepage of our website atwww.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'd 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 forecasted 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 Glenn Warren, President and CFO and Dave Conalango, 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% 20% of total drilling and completion capital in 2022 through 2024 in exchange for a proportionate working interest percentage in each well spud. QL will participate in every well that Antero drills over the 4 years starting with wells that were spud as of January 1 this year, so as of about 7 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 4 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 program. 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. 2nd, since over 1400 of Antero's 2,000 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 1400 AR locations represent approximately 38% of the remaining liquids rich core locations in Appalachia. 3rd, 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 blowouts 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 Cash Flow 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 $260,000,000 over the next 5 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 capture $75,000,000 of additional midstream fee incentives.
We are estimating $50,000,000 of drilling carry under the drilling partnership based on strip pricing and interest expense savings of $20,000,000 And finally, most of the $400,000,000 of free cash flow 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 Feet 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. Stream.
The incremental gross volumes generated by the partnership should result in AR achieving additional LP gathering earnouts totaling $76,000,000 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 1 year after the tranche is drilled that total approximately $50,000,000 by achieving certain IRR thresholds. Now let's turn to slide number 8 titled Enhanced Free Cash Flow Profile. In total, the drilling partnership is expected to increase AR's free cash flow by $400,000,000 compared to our base plan. This equates to over $1,500,000,000 of free cash flow through 2025 based on today's strip prices.
This increase in free cash flow results in a substantially lower leverage profile from 3.1 times today to under 2 times this year. Remember, this free cash flow profile is based on a backwardated strip price. If 2021 strip prices held flat through 2025, we would expect Antero to generate $3,500,000,000 in free cash flow. That is at $2.90 gas and $35 per barrel C3 plus 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 1865 of those premium locations or 36% of the total. In the Ohio Utica, we estimate roughly 1100 premium undeveloped locations of which Antero holds 210 or 19% of the total. Beyond that, we estimate that there are 1600 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 the 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 toward 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 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 5 year range only a few months ago to the bottom of the 5 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 5 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.
Allowed 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 rescom 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, though 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 plus pricing has risen from $27 per barrel in the Q4 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 plus 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 next winter. Demand for LPG continues to steadily grow for global Rescom 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 pull 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 in NGL sold domestically. Mariner East continues to deliver as a world class asset, one that has been critical to supplying 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 Transfer's Marcus Hook Industrial Complex, where Antero markets its export product as one of the facilities anchor shippers will now enjoy a shipping advantage to both Europe and Asia. While ample U.
S. Export capacity has resulted in lower dock premiums to Mont Belvieu, the overall effect of a debottlenecked U. S. Market on Antero has proved positive, resulting in stronger overall C3 plus realizations as has been evident in our Q4 results and 2021 estimates to date. With that, I will turn it over to Glenn.
Thank you, Dave. Good morning. A bullish NGL price outlook is very encouraging for Antero due to our position as the 2nd largest NGL producer in the U. S. Producing 132,000 barrels a day of C3 plus in the Q4 last year.
At that production level, every $2 per barrel or $0.05 per gallon change in C3 plus pricing has a $97,000,000 impact on cash flow. You can see that lower right on slide number 14. A key catalyst to Antero's self driven plan to number 1, address near term maturities and number 2, fill our premium Feet 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 $1,100,000,000 of committed funds through an overriding royalty transaction, a volumetric production payment and a drilling partnership with 3 outstanding counterparties, all leaders in their respective spaces. Those are 6th Street Capital 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 No Term Structure. In late 2019, we announced a deleveraging program with a goal of addressing our near term maturities. Since then, we have eliminated 2 point $3,000,000,000 of near term maturities and reduced absolute debt by over $800,000,000 As you can see in the maturity schedule at the bottom of slide, we now have just $574,000,000 due over the next 4 years, a dramatic improvement from the nearly $2,900,000,000 we had due over that timeframe at the beginning of the program. Slide number 7 titled Significant Leverage Reduction is new and it illustrates how the recent financing transactions combined with expected free cash flow have and will dramatically 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 2 recent senior note offerings, that's net of the bond redemptions for 2022s, which totaled $525,000,000 after calling the 2022 notes, the convertible senior notes equitization, the $51,000,000 contingency payment related to the royalty sale and our 2021 projected free cash flow of at least $500,000,000 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 results in our leverage ratio declining from 3.1 times at year end last year to below 2x 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 Q4 was $299,000,000 a slight increase from the year ago period as lower operating costs and increased production offset motor realized prices and realized hedge gains. Our realized natural gas price after hedges averaged $2.76 per Mcf, representing a $0.10 per Mcf premium to NYMEX. C3 plus NGL price was $27.64 per barrel for the quarter. As Dave mentioned, that's running at about $39 per barrel today.
That was an $0.84 per barrel premium to Mont Belvieu pricing and a 26% increase from the prior quarter as we benefited from premium international prices. And finally, free cash flow during the quarter was $155,000,000 On the operations front, we placed 11 horizontal Marcellus wells to sales during the 4th quarter that had an average lateral length of 15,780 feet. 10 of these wells that had 60 days of initial production set a new company record averaging 33,900,000 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 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 percent 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 and Production Council or AXPC, which earlier this month announced an 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 summarized this is the position of strength we're in today following the execution. We have significant scale as the 3rd largest natural gas producer and 2nd largest NGL producer providing attractive exposure to strengthening commodity prices. The drilling partnership we announced today incrementally boosts our free cash flow profile by $400,000,000 over the next 5 years and to over $1,500,000,000 in total over the next 5 years, including that $400,000,000 based on today's strip prices.
As Paul mentioned, that $3,500,000,000 over the 5 years at 2021 strip held flat, that's $2.90 gas and $35 C3 plus 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 reduced total debt by $800,000,000 issued $1,500,000,000 of new senior notes and redeemed our 2021 2022 maturities. This leaves just $574,000,000 senior note maturities through 2024. These can easily be addressed with our projected liquidity of $1,900,000,000 at the end of this year.
Further, we expect to achieve our leverage target of under 2x this year. These achievements while our industry and the world face 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.
Thank you. Ladies and gentlemen, we will now be conducting a question and answer session. Our first question is coming from the line of Arun Jayaram with JPMorgan. Please proceed with your question.
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 plus volume guide for 2021?
Yes. Arun, this is Mike Kennedy. We elect obviously not to pay our royalty owners in 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 to Antero and paid our royalty owners in 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 $50,000,000 negative cash flow amount related to processing uneconomic 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 with a 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 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, Ben, it would have been flat to $0.10 premium was our initial guidance. Over the last week, we've been able
to track
some of our gas to where it's needed most, and that enabled us to capture about an incremental $75,000,000 of revenue. Dollars 50,000,000 of that will be in realizations, $25,000,000 will be in lower marketing expense. So we did adjust our realized guidance for that $50,000,000 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 occur in the Q1.
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.
Thank you. Our next question is coming from Subash Chandra with Northland Securities.
On the full year outlook that you have, it looks like the CapEx is around $6.35 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 4 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 and 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 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.
Thanks. And as a follow-up, can you sort of give us a picture on how NGL volumes are shaping 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 ship more and export more in the Q1?
Yes. I should include in my first comments, the gross wellhead volumes is flat year over year. It is truly a maintenance capital volumes. Obviously, you had elevated volumes in the 3rd Q4 as we had growth capital in the first half. So the NGL volumes in the first quarter will be down similar to what the guidance is because of lack of completions in the 4th quarter but also because all of the economics are clearly economic at $40 per barrel.
On the there has been no disruptions. It will be the same mix between export and selling at Hopedale.
Okay. Thanks guys.
Thanks, Subash.
Thank you. The next question is from the line of Nate Svensson with Truist. Please proceed with your question.
Hi, all. Thanks for taking my question. So, I wanted to get into your Feet commitments a
little bit with the new drilling partnership.
So I know you get into this on Slide 6, I think, but wanted to talk how things have changed versus your previous expectations. So I know you had previously talked about the potential for Feet volumes to decline by 8 10 millimeters millimeters millimeters millimeters
millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters
cf 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 FTE roll off, What annual fees may look like? And any comments you can provide on net 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 BBT per day going down to 3.130 by 25. Now the difference to drilling JV is a lot of that is now filled by the drilling partnership.
So by the year end 'twenty five, 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 D and C CapEx of $5.80 to keep production roughly flat. And now your new CapEx gets slightly higher at $5.90 with production dropping by about 6 point. And I know you touched on the liquids portion of that in answering Arun's question, but wondering if you can just touch on any drivers to explain that difference and if anything have changed in your assumptions between December and now beyond the new drilling partnership?
Yes, yes, nothing's really changed. Can't really talk to $10,000,000 of capital, but in this size of a company. But when you look at the average for $150,000,000 So we're not going to have any sort of allocation of liquids solely to Antero. So that gets you down to $3,400,000 And then we sold the VPP midyear July, which is $50,000,000 a day, and that gets you to 3.35,000,000 which is the midpoint of our guidance.
Okay, great. Thanks very much.
Thank you.
Thank you. Our next question is from the line of Jeffrey Lampardan with Tudor, Pickering, Holt. Please proceed with your question.
Good morning. Thanks for taking my questions. My first one is on capital allocation across the portfolio around the Marcellus and 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 5 year plan. And the mix is it's roughly ninety-ten Marcellus, 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'll roll out later today. So you'll see a little bit more detail there.
But it's primarily Marcellus focused with some Utica and it varies by the year. I mean we plan to drill a few Utica wells this year, a couple of pads anyway.
Okay. I appreciate it. And then secondly, I 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?
No, that's a good question. That's the way we built the plan was off of maintenance capital throughout the 5 year outlook and that you see on the page there. So we're essentially holding maintenance capital around that 5.90, 600 number. It bounces around a little bit each year, but that's generally the outlook. And I think over the 5 years, it actually we're spending actually a little bit less than we would have pre the drilling partnership and that's excluding any kind of carry payment.
But it's actually down a little bit, I think $50,000,000 or so over the 5 year plan. So that's absolutely right. It's a maintenance capital program for AR for the next 5 years. That is the plan, certainly for now to generate maximum free cash flow and pay down our debt profile.
All right. Thank you.
Thank you. Thanks.
Thank you. Our next question is from Robert Raymund with RR Advisors. Please proceed
So just a quick question here. So 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 in excess of $500,000,000 of EBITDA in the Q1 and you have your entire revolver paid off by the end of June, right, as we think about a $3,500,000,000 total free cash number, right, how do you plan on or think about allocating that against the market cap as you guys make the point, right, that is less than the full $3,500,000,000 and a free cash flow yield on an equity that's well over 25% at this point?
Yes. That's a great question. So I couldn't have said it better myself. That's a big number. And once again, that would be holding gas flat at 2.99x for the 5 years.
And there are a lot of views out there on that. Some feel like that's it's going to go higher certainly in the next few years. And then holding NGLs flat, the C3 plus at $35 a barrel, that's where you get to that 3 point 5 $1,000,000,000 number. So easily, I mean, the first use of proceeds is to pay down debt just as you cited and pay down that credit facility and continue to pay down our debt until we get below $2,000,000,000 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 and 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 have that kind of 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 out of free cash flow here, right, over sort of a 2 to 3 year window. And I may be more aggressive on propane prices, but net of $60 oil and shortage we have, that's one person's opinion, but that's how I'd be thinking about it. Thank you.
Yes. Thank you. Yes. Thanks.
Thank you. Our next question is coming from Holly Stewart with Scotia Howard Weil. Please proceed with your question.
Good morning, gentlemen.
Good morning, Howard.
Maybe just a question, appreciate all the details on Slide 9 on just the inventory in the basin. Glenn, I'm curious your thoughts and maybe how does this impact your overall view and thinking on just on M and A?
Yes. Thank you, Holly. Appreciate the question. Yes, I mean, it's obviously I mean, we're not driven to do M and A for inventory reasons necessarily. I mean, that's well in hand with a couple of 1,000 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 on inventory. So that's not likely to be a driver for us in M and A, but there are other reasons that you do acquisitions as well, of course. Sort of one of the points is, yes, the basin just doesn't have that many years of running room at the 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 Southwest Marcellus and the 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. So just using easy math, let's say it's close to 1,000 completions a year. If there are only 5,200 Premium Marcellus and 1100 Utica, that's only about 6 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 of point to a lot more activity, not drilling activity, but consolidation activity.
I think you're probably right.
Yes. 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 Q1 of 2018, where you turned that net marketing expense into a $0.27 benefit. I know you broke out sort of the $50,000,000 $25,000,000 revenue versus net marketing expense. I mean, what does it take
to kind of, I guess, flip the switch
and have
another quarter like that, that 1Q 'eighteen from a net marketing expense standpoint? Yes.
I think that was the polar vortex here in the East Coast. So you're seeing another winter weather event, so that'll most likely occur this quarter as well.
Yes. I mean, the interesting thing about this one is
it's still ongoing. It's just so broad the impact of this and we're still seeing premium prices out there. So and who knows what happens from here with storage and all that. So it's going to be an interesting 6 weeks, I think the next 6 weeks. Yes.
And maybe Glenn, just a follow-up to that. Do you have like a percentage that you could share on just I guess the way I 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 bid week. 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 $450,000,000 $500,000,000 a day range is kind of what we have available depending on pipe capacity and all that to move around the system and whether that's Chicago, Midwest or Gulf Coast. So it's a pretty significant number for us.
Wow. Okay. Thank you, guys.
Thanks, Allie.
Thank you. We have reached the end of our time for the question and answer session. So I'd like to pass the floor back over to management for any additional closing comments.
I'd 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.
Ladies and gentlemen, this does conclude today's teleconference. Once again, we thank you for your participation, and you may disconnect your lines at this time.