Chesapeake Energy Corp (CHK) 2016 Q3 法說會逐字稿

Good day and welcome to the Chesapeake Energy Corporation Q3 2016 conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Brad Sylvester. Please go ahead.

Thank you, Ashley. Good morning and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2016 third quarter. Hopefully you have had a chance to review our press release and the updated investor slides that we posted to our website this morning.

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by a reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections, and future performance, and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and in other SEC filings. Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release.

With me on the call today are Doug Lawler, Nick Dell'Osso, Frank Patterson, and Jason Pigott. Doug will begin the call and then will turn call over to Nick for a review of our financial results before we turn the teleconference over to Q&A.

So with that, thank you again. And I will now turn the teleconference over to Doug.

Thank you, Brad, and good morning. Over the past year, we have continued to make significant progress in building a stronger Chesapeake for the future. During our analyst day held a few weeks back here in Oklahoma City, we highlighted the strength of our asset base, technology, and expertise.

To briefly summarize, the financial and operational improvements of the Company over the past few years are foundational and differential. We have reduced our total leverage by $10.9 billion, reduced cash costs by roughly 50%, substantially improved capital efficiencies and productivity, and materially improved midstream gathering costs -- all to build a more competitive, profitable Chesapeake that we forecast in 2018 to achieve free cash flow neutrality and the ability to generate more than $3 billion in EBITDA. All this progress has been made despite depressed commodity prices.

At our analyst day, we released significant technical detail regarding the potential of our oil and gas portfolio -- notably, the estimated net recoverable resources of 11.3 billion barrels of oil equivalent. We provided a roadmap that highlights the opportunity for profitable and efficient growth through our captured resources over time, along with projected financial results through the end of the decade under certain reasonable price assumptions. I would like to update you today on a couple of operational results of interest since our analyst day.

In the Haynesville, we are currently fracking a 10,000 foot lateral well with 50 million pounds of sand, or roughly 5,000 pounds per lateral foot, at ultra-tight cluster spacing. This completion will have the largest number of stages we have ever pumped in the Haynesville in a single well, and the well should be placed to sales in the next few weeks. We are recognizing transformation value improvements in this asset, and we look forward to sharing more results of our progress in the Haynesville in the near future.

In the Mid-Continent, we recently introduced a new concept area that we call the Wedge, in which Chesapeake has approximately 870,000 net acres under lease and where we are targeting several oil- and gas-bearing stacked horizons. We have two recent step-out wells in the area that are currently producing 1,000 to 1,400 barrels of oil equivalent per day, 50% to 70% of which is oil, from one-mile appraisal wells.

We believe the development potential in this area, utilizing two-mile laterals, is tremendous. We're excited about the potential from these assets and with our other operating areas as we look ahead to 2017.

With an inventory of over 17,000 wells still to be drilled across six major operating areas, with 5,600 of those wells currently having a rate of return greater than 40%, we are confident that the Chesapeake operating machine is stronger today than at any other time in our history.

Turning to the results from the 2016 third quarter, our total production was 638,000 barrels of oil equivalent per day, an increase of over 2% compared to a year ago, adjusted for asset sales. In our IR slides we shared this morning, we detail the production impact of our year-to-date divestitures to demonstrate the strength and resiliency of our production base, even after those adjustments.

While total volumes from our divestitures in the Mid-Continent area, the Barnett -- and now pending transaction to the Devonian and Haynesville -- were primarily gas, the full impact of approximately 8,200 barrels of daily oil production, divested since the beginning of the year, was recognized in the 2016 third quarter. We have already started to replace these oil volumes with new volumes from the Eagle Ford and the Mid-Continent, and our total net oil production for October is projected to be approximately 91,000 barrels per oil per day. With our productivity and capital efficiency improvements, and subject to final capital allocation and commodity prices, we currently forecast that we will replace the divested oil volumes in 2017 and begin a strong oil growth trajectory.

In the slides, we also highlighted our forecast the production growth over the coming quarters. We are currently projecting an exit-to-exit increase in total production from the fourth quarter of 2016 to the fourth quarter of 2017 of approximately 7%, adjusted for asset sales. More importantly, we are projecting an exit-to-exit increase in our oil production from the fourth quarter of 2016 to the fourth quarter of 2017 of 10%.

Looking further forward to 2018, the growth continues even stronger. We previously estimated that our 2018 year-over-year total production growth rate would be in the 10 to 15% range. However, when looking at exit rates from 2017 to 2018, we see a strong trajectory throughout the year. We are currently projecting an increase in our total production for the fourth quarter of 2017 through the fourth quarter of 2018 of approximately 15%, primarily driven by an exit-to-exit increase in our oil production from the fourth quarter of 2017 to the fourth quarter of 2018 of over 20%.

We believe our Eagle Ford and Mid-Continent assets will be driving this growth, and the Powder River Basin will be beginning to accelerate as well. These numbers are a reflection of our capital efficiency, productivity, and the power of our portfolio.

Turning to our costs, operational efficiencies are driving lower production expenses. We see this trend continuing, both in the fourth quarter of 2016 and for the full year of 2017; and as a result, we have reduced our production expense guidance for both time periods. We also believe the efficiency-related cost reductions are sustainable beyond 2017.

Our G&A expenses for the 2016 third quarter were up year-over-year due to the lower recoveries of G&A expenses due to asset sales and a slight increase in stock-based compensation and compensation related to achieving certain annual performance goals, tied to capital efficiency improvements, cash cost reductions, and gathering process and transportation expenses.

On the A&D front, we currently have gross proceeds from divestitures either closed or under a signed PSA of approximately $1.3 billion in 2016, or about $1 billion net. We are on track to achieve our stated asset divestitures target of more than $2 billion in gross proceeds, all of which should be closed in the first quarter of 2017. We will continue to optimize our portfolio in 2017, accelerating value for our shareholders.

In closing, I am pleased with the significant and foundational progress we have made in reducing our debt, eliminating complexity, and lowering our costs. We will continue building on our record of performance and efficiency improvements, and we will continue to drive for greater profitability and competitiveness. We remain committed to further improving our balance sheet, and we are uniquely positioned to create value for our shareholders through our high-quality assets; our driven, talented employees; and a liquidity runway built out for several years.

We are excited about our opportunities and our progress. We have more to do, and the momentum behind Chesapeake Energy will continue to build.

I will now pass the call to Nick, and then we will follow up with questions on the call.

Thank you, Doug, and good morning, everyone. Let me start out by saying that this has been an extremely busy quarter as we continue to recapitalize the balance sheet, improve operational efficiencies and flexibility, and position the Company for profitable and efficient growth.

We realize that there have been a tremendous amount of adjustments and moving parts to model recently, with a lot of related explanations to cover, all of which highlight very positive trends in our underlying business. I will try to summarize the highlights here today.

While there were several gives and takes this quarter related to LOE, G&A, gathering and processing and transportation, and interest expense line items, the primary driver of lower EBITDA compared what we had expected this quarter was found in our marketing segment, the impact of which was just under $30 million. This was primarily driven by the loss of margin due to the sale and acceleration of value of a long-term gas contract and some out-period charges related to assets we are selling in the Barnett and Devonian.

We continue to focus on reducing our cash costs and balance sheet leverage. And we were able to make significant progress in these areas over the past several months.

On operating cost side, we have not only reduced our LOE expenses per unit of production, as Doug mentioned, but we have also achieved significant improvements in our midstream and downstream cost structure going forward. With the closing of the Barnett Shale transaction earlier this week, we are removing a significant amount of gathering, processing, and transportation expenses.

For the 2016 fourth quarter alone, we will be removing two months of GP&T costs, including the minimum volume commitment, [settling] approximately $235 million related to the asset. We also decreased our Mid-Continent gathering fees effective July 1 of this year and expect the same in our Powder River Basin area, effective January 1, 2017. As a result, our total gathering, processing, and transportation expenses -- we anticipate our gathering, processing, and transportation expenses to decrease by roughly 8% in 2017. These changes reduced our commitments and improved the economics of future drilling opportunities, leading to significantly improved operating flexibility as we continue to evaluate our capital allocation in pursuit of the projects that will maximize shareholder value.

On the NGL side of our gathering, processing, and treating costs, we have seen an increase this quarter due to higher than expected levels of ethane rejections. This was offset by an increase in the realized prices we receive for NGLs, as our mix shifted to heavier liquids following our Granite Wash sale earlier this year.

Note in 2017, we are guiding to higher NGL gathering, processing, and treating costs due to revised contracts in the Mid-Continent area, where increasing volumes will be gathered by under contracts structured with processing fees, allowing us to receive a greater uplift in net NGL revenues. Therefore, we believe we will continue to see improved net NGL revenues that will offset the increase in processing costs.

Our primary financial focus has been the reduction of both our near-term and total debt and improvements to our near-term liquidity. Over the past 12 months, we've been able to reduce our debt maturing or puttable in 2017 through 2019 by $3 billion. In total we have removed approximately $2.1 billion in principal amount of debt over the past 12 months, making good progress on our longer-term goal of $6 billion to $7 billion in total debt.

As part of extending our maturities, we entered into a $1.5 billion secured five-year term loan facility during the third quarter and used the net proceeds in a tender offer for maturities primarily in the near to midterm of our debt maturity stack. Further, in October we issued $1.25 billion principal amount of unsecured 5.5% convertible senior notes due 2026, which essentially pre-funded our remaining 2017 and 2018 maturing and puttable debt. And we have already purchased approximately $100 million of 2017 and 2018 maturities at a discount to make-whole since closing on the convert.

As a result of these steps, we sit with $3.7 billion of liquidity, including approximately $650 million of cash today after having close on the Barnett Shale transaction earlier this week. I would note that we have formulaically reduced our availability under our revolver by a little over $200 million as a result of asset sales. As previously noted, our current reserves calculation is well in advance of the level to support the full $4 billion.

We are currently scheduled to redetermine our borrowing base next summer but do have the option to request a redetermination sooner. At the moment, we obviously have ample liquidity and do not anticipate our pending asset sales having any further impact on this calculation.

Through all of these cost structure improvements, asset sales, and balance sheet transactions, we have greatly improved our cash flow profile and have cleared the debt maturity runway, allowing us to focus on our operations instead of our obligations. Additionally, to further improve our capital structure, we exchanged an aggregate of approximately 110 million shares of common stock for approximately $1.2 billion of liquidation value of preferred stock at a discount of approximately 40%.

On the A&D front, we have announced that a PSA has been signed or our Devonian assets, and we intend to buy back the VPP related to that asset when consummated. We believe that cash to the Company will be a nominal net positive as a result of these transactions. When these transactions are completed, we will have only one remaining VPP -- that one being in Northern Oklahoma.

We've also noted that we are looking to sell approximately 126,000 net acres of our Haynesville position in two separate sales packages. Bids are in for the first package, which has net production of approximately 30 million cubic feet of gas per day. We are pleased with the indications, which we expect to be at a substantial multiple over the EBITDA we projected on the PDP of this asset in 2017 of approximately $15 million. We expect to proceed the execution on the sale, with an anticipated close in the first quarter of 2017.

The data room for the second package has just been opened. This package has net production of approximately $45 million cubic feet of gas per day and was expected to contribute about $25 million in EBITDA from those PDP volumes in 2017. Based on the current interest and the need by buyers to digest the recent and upcoming strong well results we continue to see with new wells in the area, we look forward to updating the market on the results of the second package in early 2017.

As noted during our analyst day presentation, our 2017 projected production guidance reiterated today has been adjusted for both the expected Devonian and Haynesville divestitures. So we kept our 2017 projected production guidance the same as previously stated back in August, despite the removal of expected net volumes of about 35 Bcf from these anticipated transactions.

With the continued volatility of both gas and oil prices, we are pleased that our hedge position for both the remainder of 2016 and 2017 is already fairly robust, particularly on the natural gas side. We will continue to monitor market conditions and may increase our positions in both gas and oil at the appropriate times. Our current hedge position is detailed in the slides we posted to our website this morning.

In closing, we are making meaningful strides in our debt reduction efforts and look to continue our progress in this area. We expect more success in the A&D market and expect to be able to discuss these transactions soon.

As Doug noted, our production remains strong. When you look to start -- when you start to look through 2017 to 2018, our production rate only gets stronger, given our highly efficient capital program in 2017.

That concludes my comments. I will now turn the call over to the operator for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Doug, although not necessarily as once earlier, could you talk about just any potential near-term and longer-term asset sale candidates?

Neal, as we've highlighted, the Haynesville is kind of our principal area of focus, if I could point to the huge inventory of resources and the strong assets we've got to drill the locations. We haven't provided any other guidance yet; although with that significant inventory across our portfolio, you can expect to see additional asset sale candidates potentially from any of the areas in 2017.

And then just secondly, just on the Eagle Ford, it looks like you continue to make a lot of improvements there. Just -- could you talk a little bit about any upside you have continued -- you might be able to see, let's say, in 2017 from either the efficiencies or lower costs?

I was just noticing on the slides that only about 25% has been drilled. So does that mean you can come back and return the existing pads to improvement there? And do you see lower costs as well?

Yes, it absolutely does, Neal. That's part of the confidence we have in some of those continued capital efficiencies, operating efficiencies. We see significant potential there.

And just as a highlight, too, as many other companies have reported -- and remember that Chesapeake's position, we often in many of our pad locations in sections have just a single well. So it's not like we are coming out with very strong, aggressive downspacing. This is a significant development opportunity, essentially from a blank slate with that many opportunities in front of us.

Great, thanks.

David Heikkinen, Heikkinen Energy Advisors.

You sound remarkably well-rested, given the amazing end to the World Series last night. I'm just hoping that my energy levels can hold in as well.

The question I was thinking about was: in the Mid-Con, can you talk about your water volumes on the Wedge wells? Is there any -- trying to get some details on zones, and I know you are not ready to do all that yet, but any indications of additional information would be helpful.

Yes, this is Frank Patterson. Depending on what zone it is, it is less than, say, the Mississippian; but we're still in the early days trying to understand it. So you've got multiple zones in there. You've got Chester, Merrimack, Osage. And each of them are going to react differently.

We really haven't got enough data yet to really give you a good feel for what the water cut is, but it looks like it's going to be less than the Mississippian as a whole. They are quite a bit different reservoirs. They are tighter than what the Mississippian play is.

And then around the Mississippian, what is the current status for water and water disposal? And any impact of earthquakes or shut-ins for your assets?

This is Frank again. We do have volume shut in. We are in compliance with the OCC's requirements. We are in the process of converting some disposal wells to shallower zones. We are also shutting in wells or managing wells that are higher water cut.

If you went to the investor conference -- with the information we have today, we can actually target lesser water cut wells in our forward program. So it's an all-hands-on-deck to manage that process. But what we're seeing today is our volumes are starting to come back with the good work the field and the teams have done on the technical side.

How much volume is shut in?

Jason, do you remember how many -- how much volume we had shut in?

I think they've got most of it opened up. With all the recompletions, we have been able to increase our capacity prior to any of the restrictions we had on -- so early on we took a hit on the water volume, but I think we are almost at full capacity right now. So any wells that are shut in are shut in just for economics and pricing situations, not due to restrictions from the water.

So your October volumes are, like, a true number. That's what I was getting at on that question. Thanks, guys.

James Sullivan, Alembic Global Advisors.

Quick question on the marketing number. Could you just help us a little bit going through the math on that? I know that you've obviously got the forward sale contract, which I think in the report you said was factored into the results. So a little bit of help on the quarterly number.

And then I know that the 2017 marketing margin was little wider than it's been in the past. Is that, I assume, as well because of the forward sale? So just any help you can give us on that, that would be great.

Sure, James. You were trailing off a little bit there, so I think I got the gist of the question. If I don't answer it fully, just come back with more.

But we did sell a long-term gas supply contract during the quarter. We had announced that previously. That had with it a mark-to-market gain on future periods of $280 million that had been in the assets section of our balance sheet.

You can think of that fairly consistent with the way you would account for a hedge, where the future value of that contract was marked each quarter and was in a gain position, so it was an asset. So that came off. That was not included -- the removal of that gain was not included in our adjusted earnings.

What we did include was $146 million of actual cash proceeds we received from accelerating the value of that contract to the quarter -- again, all received in cash. And we want to really highlight that, and so right in the paragraph where we discussed our -- the things that we adjusted out, we highlighted that we included that in.

The reason we chose to include it in is that the realized portion of that contract has been in now for several periods in a row. And if you didn't include the acceleration of value anywhere, you would likely have a miss of not seeing that contract trend continue.

So we thought it was important to highlight for investors that that value was accelerated and came in. And then you should adjust your marketing margin going forward for the fact that we will not see the value of that contract continue to pay out in future periods, as, again, it all accelerated into the third quarter of this year.

I will note that the value of that contract was pretty high on a per-quarter basis in 2016, as basically it was a $4 floor gas delivery contract. And so during the periods of 2017 were gas was very low, the profit on that contract was pretty high.

Going into next year, of course, as the strip returned to the neighborhood of $3, the value of that contract would have been coming back in a little. But still, obviously, it was good contract that -- we were pleased to accelerate the value of almost $150 million in cash this quarter at a time where we can use it to apply to our balance sheet.

Okay, thank you. That's a very complete answer. I appreciate all that.

Just -- if I could ask for also just a little bit more detail, switching over to the Haynesville here: you guys gave out the two packages that you are working on. I think you gave the -- your anticipated PDP to EBITDA. Can you break out, just for each of those, the acreage number? I know you have given an aggregate acreage number that you're looking to sell. But if you could give for the two packages -- I'm not saying you want to go into this level of detail -- but the acreage number, the slowing production, and then just if you could repeat that anticipated EBITDA number, that would be very helpful.

Yes, so, there's a little more acreage in the southern package than there is in the northern package. It's a bit of a mix of -- it's not all core Haynesville acreage. There is a little bit of Bossier acreage in there as well.

We haven't, I don't think, broken out the exact acreage of the north and the south, and we will probably hold off from doing that today. But the southern package has more acreage, less cash flow. Northern package has less acreage, more cash flow is the way to think about those two.

Okay, great. That's very helpful. Thanks, guys.

David Tameron, Wells Fargo.

Doug, back to the Haynesville, can you go through what you said your most recent completion is? And how should we think about that as far as -- what do you need to see additionally from that well in order to justify the higher completion costs?

Yes, you bet. Actually, I'm going to have Jason answer it. This is so cool, it's -- you are going to love it.

So this is Jason Pigott. We've got a couple tests underway right now. We have brought online and announced it at our analyst day the first 5,000 pound per foot job. But that was on a shorter lateral.

We've got a really good test going on there right now, where we've got a 3,000 pound per foot job flowing right beside one above 5,000 pound per foot jobs. We have kind of tried to manage them and keep them as equal as we can, but the 5,000 pound per foot job is flowing back at -- I guess a week later, 17 million cubic feet a day and 7,900 pounds -- like the 3,000 pound job is 14.5 million and 7,500 pounds. So we've definitely seen a big gain from the -- going to 5,000 pounds per foot. And we're excited about it.

We've updated our costs. It cost us about -- if you extrapolated this to a 10,000 foot well, it's about $600,000 more to go to the -- well, $1.2 million if you go all the way from 3,000 to 5,000 pounds. So not a huge incremental investment, considering the gain that we see already on these side-to-side tests.

The record well that we also highlighted with the 50 million pounds is -- got all of its plugs drilled out and will be coming online Friday. So we are really excited about that. It will be the first 10,000 foot well with this bigger design on it.

And then Doug highlighted in his notes one that tested the limits of even tighter perf clusters with the big job that they are getting ready to do as well. So we've got several exciting tests coming online. We are very encouraged by the incremental performance from the increased sand and perf cluster spacing.

We've got several other tests with 4,000 pound jobs that kind of split the difference coming up. It's a very dynamic program in the Haynesville, but one we are very excited about. And it seems that every little bit extra we do to these wells is producing a very positive return to us.

Yes. So hey, Dave, I wanted to just add to that -- so think full Bcf in 120 days.

Okay. All right, yes, that's a big well.

I guess one more, just -- I'll go with this one. Doug, when I start -- or whoever -- when I start thinking about sand, you start talking about those volumes with that 50,000 pounds: logistically, if that becomes your standard design, how do you manage that from an operational standpoint, just getting the sand from the -- from wherever it's coming to the well site? And especially when you start thinking about under development program longer-term over the next year or two, how do you manage that?

Well, I think it's just like any of our operations; there's quite a bit of detail and planning around it. And just as you have experienced and seen with Chesapeake in the past, this Company is capable of handling significant operations, significant detail and complexity in our operations, and managing of that as we narrow in on the optimum design. Won't be any trouble for us at all.

Keep in mind, also, that a lot of the cost efficiencies that we have accomplished have been a result of synergies and the number of jobs -- the planning and engineering that goes into completing a very high number of stages on a daily basis, which creates significant opportunity for our contractors and service providers. And so we have great relationships there, and their interest in doing work for Chesapeake and being part of our program is very strong. And that helps us on the logistics and planning side as well.

I don't know, Jason, Frank, if you have anything you want to add to that?

I think the big thing for us, though, is we do a lot of work on the preplanning of these jobs before we even show up on location. For one of these Haynesville 50 million pound jobs, there is 1,000 trucks full of sand that pull up there.

But we did it our first try without a hitch, so it's just something that we do well. We plan ahead. Everybody knows what they are doing. That allows us to get more stages per day done, but also handle logistics as well.

The other thing I would add -- this is Frank -- is I think there's, kind of in your mind, maybe thinking about our entire inventory receiving this type of completion design, but we are designing our completions for the rock type and for the play. So it's working really, really well at high concentrations in the Haynesville. It might work in other plays, but other plays we might have a different recipe. So we're not talking about that type of sand in every single play.

I'm going down there in the next couple of weeks, Dave. If you want to go, let me know.

All right. Sounds good. Thanks for the -- yes, I was just thinking about how many trucks it takes to get in there, so -- but thanks for the color. I appreciate it.

Jacob Gomolinski, Morgan Stanley.

Just had a quick question on the -- just a quick clarification on the $280 million supply contract derivative and the $148 million -- $146 million cash addition. Just trying to get to sort of what is an acceleration versus what would have been in Q3 to get to a run rate EBITDA number? Of that $146 million in cash realized that was added back, what would have been in Q3 sort of on a run rate basis?

It had been running in the neighborhood of $15 million to $20 million. I didn't go back and calculate exactly what it would have been just for the quarter if that had stayed in place. Again, it's on a $4 floor. So that would have been -- gas was a little [less] Q3 to Q2, so it would have been a little less in Q3.

Okay. Thanks. And then on the -- I think you had said pro forma cash post the Barnett sale was $650 million. I don't know if you're able to just kind of do a walk from the -- there's, like, the $4 million as of September 30, the $900 million from analyst day, and the $650 million. I don't know if that's driven by the payment to Williams, or if there's something else to kind of go from the $900 million to the $650 million?

Yes, it you got it. It's basically the payment to Williams is the big move there. It was $334 million. We had some other cash come through the Company and then back out for contracts associated with the Barnett. So fair amount of moving pieces there. The biggest piece is Williams.

Okay.

(multiple speakers) done. The important -- the reason to have given that number today is that is done, and that's where we set from a liquidity perspective after all of that.

Okay, great. And then I just want to make sure I heard correctly on --.

One other piece I just want to highlight there -- sorry to butt in, but when you think about reconciling back to the proceeds we received from our convert at the beginning of October, we have already put to work about $100 million of that in open-market purchases of 2017 and 2018 notes.

Right, right. Great.

And then just the last question on the Haynesville asset sale: I think -- were you saying that the -- is the initial sale still expected to be before the end of the year, or is that moving into Q1 of next year? And if it is moving into Q1, is that just to give buyers more visibility into the most recent high-intensity well completions?

We will have an announcement on the first package before the end of the year. And whether or not it closes before the end of the year, it's kind of hard to predict as you get into holidays and, frankly, not that meaningful to us. Want to get the deal right, and get it papered right.

Second deal -- like I said, we just opened the data room. And so not sure that we will be able to announce that before the end of the year; and again, want to make sure that we have the time for buyers to digest all of the things that Doug and Jason have commented on this morning with respect to the Haynesville and the incredible well performance there. So might stretch that one out a little bit in order to get the right answer.

Great. Thank you very much.

Thanks, Jake. Thank you all for joining us today. Please feel free to reach out to Brad. We are happy to share any additional information about our progress and the accomplishments of the Company. And that concludes our teleconference. Thank you all for participating.

And again, ladies and gentlemen, that concludes our conference for today. We thank you for your participation, and you may now disconnect.