And welcome to the Cabot Oil and Gas Second Quarter 2020 Earnings Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. At this time, I'd like to turn the conference over to Dan Dinges, Chairman, President and Chief Executive Officer.
Please go ahead.
Thank you, Allison, and good morning to all. Thank you for joining us today for Cabot's Q2 2020 earnings call. As a reminder, on this call, we will make forward looking statements based on our current expectations. Additionally, some of our comments will reference non GAAP financial measures. Forward looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in yesterday's earnings release.
Despite the ongoing global pandemic's impact on natural gas demand during the Q2, which contributed to the lowest average quarterly NYMEX price since the Q3 of 1995, Cabot was still able to generate positive net income of $30,400,000 or 0.08 dollars per share. These results demonstrate our uniquely advantaged low cost structure that we have continued to improve upon year after year, allowing us to deliver profitability and positive returns on capital even the very trough of the natural gas price cycle, which is where we believe we are today. While we are seeing green shoots emerging in the natural gas market, which I will get into in more detail later in the call, I want to commend our team for delivering another profitable quarter in the face of the recent headwinds across our industry. Operationally, our team delivered another strong quarter with our daily production of 2 point 229 Bcf per day, exceeding the high end of our guidance range. Our realized prices before the impact of derivatives represents a $0.30 differential to NYMEX, which is in line with the low end of our full year guidance range and is a significant improvement relative to a $0.44 differential in the prior year comparable period.
Additionally, all of our operating expenses were in line with or below our guidance ranges for the quarter, demonstrating our continued focus on cost control. In the 2nd quarter, we generated our 1st quarterly free cash flow deficit since the Q2 of 2018, but it's the only our second free cash flow deficit in the last 17 quarters. Given the historically low natural gas price environment during the first half of this year. In addition to the combination of our first half weighted capital program and a second half weighted production profile, our plan for 2020 was expected to generate a slight free cash flow deficit during the 1st 6 months of the year before turning to a free cash flow positive program in the second half of the year. Ultimately, at the current strip, we still expect our capital program for the year to be fully funded within cash flow and to generate enough free cash flow to cover the majority of our regular dividend.
Our balance sheet remains exceptionally strong with a net debt to trailing 12 month EBITDAX ratio of 1.2x at the end of the quarter. Subsequent to the quarter end, we used cash on the balance sheet to repay our $87,000,000 tranche of senior notes, which matured this month. It is important to note that while we have seen a moderate expansion in our leverage metrics this year as a result of trough natural gas prices, we anticipate a significant compression in our leverage ratio next year at the current strip. This compression is driven not only by the expectation for higher EBITDAX resulting from improved price realizations, but also from lower absolute debt levels as we continue to pay down our near term maturities with free cash flow. In yesterday's release, we reaffirmed our full year production guidance range of 2.35 to 2.375 Bcf per day with the midpoint of the range implying a flat production levels year over year.
Additionally, we have reaffirmed our capital program of $575,000,000 We also initiated our 3rd quarter production guidance range of 2.4 to 2.45 Bcf per day, which represents a 9% sequential increase in daily production. Midpoint of our guidance range for the Q3 and full year imply that production volumes in the Q4 will be roughly flat to the Q4 of last year. On the capital side, we expect spending to sequentially decline in both the 3rd and 4th quarters driven by reduction in our completion activity during the second half of the year. The macro outlook for natural gas markets is obviously top of everyone's mind, especially given the stark contrast between the current market conditions and where we believe these dynamics could be during the winter withdrawal season. On the demand side, while LNG exports have continued to disappoint this summer, we believe that July August will likely mark the trough for the export levels, resulting in a gradual improvement in LNG utilization rates beginning in the latter part of the third quarter as the U.
S. Experiences fewer cargo cancellations. Our base case expectation is that as we move into the winter, higher global gas prices will put U. S. LNG back in the money, leading to significant improvements in utilization rates and a corresponding increase in export related demand for natural gas.
While we anticipate some reduction in power burn this winter due to reduced cold gas switching, we would expect stronger residential and commercial demand year over year assuming normal weather, which should offset any power related demand loss. On the supply side, we continue to see the potential for over 6 Bcf per day reduction in production year over year this winter, driven only driven not only by the sizable activity cuts in natural gas focused basins, which we think is good, but also from steeper cuts in oil focused basins resulting in the expectation for continued structural declines in associated gas production, Given the ongoing focus across the industry on capital discipline, including the prioritization of capital allocation on debt reduction and return of capital to shareholders over growth, we believe any future recovery in natural gas supply will be much slower than in prior cycles. And ultimately, the market will need to see higher prices to either insenitize more production or to disincentivize LNG exports and economic coal to gas switching. While there are certainly risks to this thesis, we remain cautiously optimistic about the natural gas market heading into this winter. We remain acutely focused on executing on a risk management strategy for 2021 that optimistically locks in hedges to protect against potential downside risk, while also remaining exposed to potentially one of the most favorable setups we have seen for the commodity in years.
While we have yet to formulate official plans for 2021, in our release yesterday, we highlighted that based on 2021 NYMEX price assumptions of $2.75 per MMBtu, which is roughly in line with the future current futures, we can deliver similar production levels as 2021 from a modestly lower capital program, while delivering a free cash flow yield of approximately 8% and a return on capital employed between 19% 20%. As we disclosed previously, every $0.10 improvement in NYMEX natural gas price is expected to increase our 2021 free cash flow by approximately $55,000,000 highlighting the upside potential if the natural gas market does in fact reach a point of inflection this winter. As we anticipate a significant expansion in free cash flow in 2021, we remain committed to disciplined capital allocation with a focus on balancing the deployment of our free cash flow next year between returning capital to shareholders and repayment of our $188,000,000 of senior notes maturing in 2021. Our capital return focus will be grounded in our base quarterly dividend of $0.10 per share or $0.40 annually and further supplemented by optimistic returns of capital, including special dividends and or share repurchases. While 2020 may ultimately deliver the lowest average NYMEX price on record since 1995, I am proud of Cabot's resiliency highlighted by our ability to deliver positive free cash flow and positive corporate returns while maintaining a strong balance sheet even in the trough of the commodity price cycle.
We will continue to execute, deliver on our plans for this year, which was formalized in February before the widespread impacts of the global pandemic and we remain optimistic about potential for an inflection point in natural gas markets this winter and the corresponding expansion in our free cash flow, return on capital employed and return of capital to shareholders in 2021. And Allison, with that comment, I will be more than happy to answer any questions.
Our first question today will come from Arun Jayaram of JPMorgan Chase. Please go ahead.
Yes. Good morning, Dan. I was wondering if you could give us a little bit more color around your thoughts on modestly lower CapEx for 2021. Maybe give us a little bit of thoughts on that.
Well, we have indicated that our 2020 program was front loaded. The remainder of 2020, We're not going to spend as much capital. We're also in the midst of negotiations with rigs and frac crews. And looking at the efficiencies we've developed in our program operationally and what we're seeing and what we think will occur with our execution contracts in the 2021 for our 2021 program, we think we will see that modest reduction in that program. Great.
Yes, if you wanted a ballpark, 5% to 10% as a number right now might be a useful number.
Got it. Got it. So something maybe in the $5.40 type of range, something like that?
Yes. Yes, that would seem reasonable.
Got it. I did want to maybe see if you could elaborate on call it some of the outlook comments on 'twenty one obviously assuming a 2.75% strip. You cited an 8% free cash flow yield, which would suggest on RMAT, call it $580,000,000 in free cash flow. Your annual dividend is about $160,000,000 I think there's a desire at the company to return at least 50% of free cash flow to shareholders. So that would suggest maybe another $130,000,000 But just maybe wanted to get your thoughts on, let's assume $275,000,000 is a good number next year.
What kind of magnitude of cash return could we see to shareholders above your dividend, again, which is around $160,000,000 a year?
Yes. We have I think we've set a pretty good clear track record of what our desire is, and that is to return as we've couched 50% of our free cash flow back to shareholders. We have our debt we're going to take care of next year. We have the dividend also. And some of our decision and what we elect to do, we would if I'm speculating here a little bit, but we would probably maintain a our dividend where it is.
We'll talk about it throughout the year and we'll look at the macro market as we look out forward. But we've also talked internally about special dividends and we haven't changed off of our position to return cash to shareholders.
Great. Thanks a lot, Dan. You bet.
Our next question will come from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning. Good morning, Jeff.
Dan, I
want to ask for a little help on 2 ideas from the press release together. First, Cabot said that it can maintain the flattish production in 2021 with lower spend. We just discussed that. And then as with your preamble, there was the note that improving demand and diminishing supply imply tailwinds for natgas pricing in 2021. One view seems quite conservative and the other one is more bullish.
So I was wondering how do we put these 2 contrasting views together to think about what may be more probable or less probable for Cabot in 2021?
Well, it's still early. We've, as you read or typically as we do, we release in February what our outlook on 2021 is going to be. We have the advantage at that point in time to be able to see what the winner has done, look at what the strip is at that particular time and we'll forecast then a much clearer definition of what our 20 21 period our CapEx will be and what we're how we're going to set our expectations. When we look at the market and at this time, we are conservative by nature. We have a what I think is a great setup for our shareholders to deliver a great deal of free cash flow.
We'll deliver that free cash flow to our shareholders versus the banks. And I think that is going to be attractive. And we have a conservative program, which hopefully it turns into that conservative program with the commodity price expectation we've stated, plus or minus $2.75 and we're comfortable with that right now. If we see continued discipline in the market and we see continued increases in demand. The LNG market comes back strong.
We do have the ability to increase our program, but we're comfortable right now messaging that our lower CapEx program in 2021 is going to deliver the same volumes.
And just to follow that up real quick, and I don't want to put words in your mouth, but it sounds like what you're saying is we've got a conservative program set up that is already going to generate attractive free cash. And if the market goes our way and we get better pricing, 1st and foremost, we're going to make even more free cash. And then maybe at some point, depending on signals, we might increase activity as a follow on. Is that fair or am I reading too much into it?
I wish I could have said it as well as you did, Jeffrey.
Okay, great. And I'll ask a follow-up that's a lot more specific. I just want to get your view on the cancellation of the Atlantic Coast Pipeline, the likely completion of the Mountain View pipeline and how you see that affecting the nat gas market in 2021, both macro and maybe on Appalachian basis as well? Thank you.
Thank you, Jeffrey. And Jeff Hutton is on the edge of his seat.
Good morning, Jeffrey. There's a lot to take in with the cash in that project, both in the grand scheme of things on pipeline development and also on specific projects. We always felt like that project was fairly long cut because of the 600 mile away, how many states they went through, etcetera, etcetera, and quite frankly, the high cost of that project, but also that project lands. It does tie in the transco force down at Station 165. We felt like that's quite a bit of gas to go into that market.
Obviously, there were some shippers that were optimistic that they'd be able to develop some more gas fired generation down there. I still think that's the case, but I think there's also ample supply on the transit system to satisfy that demand. So again, initially and even today, we still think that there was too much gas in that region. We were somewhat concerned that it would saturate the market to the point that it would bleed upstream into the DC area where we're actively marketing gas. And so quite frankly, the cancellation of that project gives us more of an optimistic view on pricing for that region.
Okay, great. That's very helpful. Thank you. And by the way, we'll see you next week.
Very good.
Our next question today is from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian. I wanted
to follow-up on a couple of the points raised here earlier. First on that mechanism to return cash to shareholders, how are you thinking you talked about the special dividend, but how are you thinking about more of a more codified variable dividend versus special dividend versus share repurchase when that time comes?
Yes. We're socializing that now internally, Brian. We have not put a framework around a formulaic delivery of that special dividend or variable dividend. As you've seen in the past, we have as similar to our buybacks, We've made those decisions. When we feel comfortable about the market, we see the near term support in the market that allows us to generate out in front of us X amount of incremental free cash.
So we're comfortable delivering a certain portion of that and in some cases, all of it back to shareholders. So I'm sorry, I'm not specific on the formula, but we have not gotten to that formula internally.
Understood. Thank you. And then my follow-up is with regards to in basin gas demand. Can you give us the latest on what your expectations are for that market and how that also sets your view more broadly on what the outlook is for U. S.
Domestic gas particularly from the power and industrial sectors?
Yes. I'm going to make a comment, then I'm going to turn it to Jeff, Brian, because it is an area that we are spending a great deal of time and focus on in basin demand projects. But one of the most recent impetus and catalyst that is, I think, driving now more attention to Northeast PA as a location for demand projects has been the agreement of tax credits that Pennsylvania will allocate to at least 4 projects that bring a large manufacturing or natural gas demand project to state and spend X amount of money, employ X amount of people, then they would receive 100 of 1,000,000 of dollars over the next 10 years of tax credits. That is a tremendous opportunity. It is out there and now in the books with the Governor's signature.
And we have had discussions with in basin demand projects, and we have had for a while a business development group that is working this opportunity for us. We like the idea of in basin projects. We can hook that up on the tailgate of our gathering system. And it is an incremental realizations to Cabot. I'll let Jeff talk a little bit about his thoughts in this regard.
Good morning, Brian. The just a quick recap, in basin demand in the Northeast corner of PA has picked up quite a bit of load over the last 4, 5 years, somewhere in the neighborhood of 1.5 Bcf a day new demand. And as you spread and look across the entire state of Pennsylvania, a lot of projects that are being built or have been built that are utilizing natural gas from the Pennsylvania area. So it's all good whether or not it's a Cabot linked project or with others. But specifically, we've talked about this in the past where we've identified a number of sites and locations with different acreage and train sizes with water, with rail, with power and obviously with our gas supply.
And we continue to talk to industries that are located in the Northeast already have markets in the Northeast. There's been some new technology developed for some very unique projects that are good year round loads. And so nothing to announce today. Obviously, we have a huge amount of activity with different manufacturing associations and associations throughout that region, including local and county market development people. So it's an ongoing process.
We found some we have some ideas and that we're working toward. Nothing definitive, but we're really happy with the half of each day of the day load that we currently have up there. And most of those deals, of course, are long term in duration because of the nature of their locations.
Great. Thank you.
Thanks, Brian.
Our next question will come from Leo Mariani of KeyBanc. Please go ahead.
Hey guys, I was hoping to follow-up
a little bit more on the kind of risk managementhedging strategy. As we sit here today, I mean, it looks like futures curve in 'twenty one is offering a little bit north of $2.65 which seems like a very robust price compared to where we sit today and certainly one where I think Cabot's economics would be outstanding. Why not try to maybe put some kind of collar structure in place to protect some of that downside at this point. Certainly recognize your bullish view on macro, but as you guys know, you're always kind of a warm winter away from potential challenges in the gas market. So any thoughts you kind of have on that would be great.
Leo, certainly a discussion regularly and internally with our hedge committee and the price we see out there in 2021 is actually north of the $265,000,000 that we see today. It is our intent to mitigate, as you say, the downside of the macro market. We have all been disappointed in the past, more so disappointed in the recent past than pleasantly surprised. We do think that there are some fundamental points that we made in my remarks that are constructive to a supportive underpinning of the market. And yes, it can go down.
And as I mentioned that the risk of that type of downside, we're fully aware of. We think our program would deliver very well at 265. It is our intent to participate in the 2021 financial hedge market, and we'll do that appropriately with the vehicles once we make the decision amongst the committee to do that. So we're thinking alike, Leo. We're pleased with where the market is right now.
And we are again looking forward to participate in the hedge market. I can't tell you when in advance we plan to do something, but we do look at it every day.
Okay. That's great color. I just wanted to follow-up on your comments regarding 2021. I know it's not guidance and just sort of an outlook, but I guess flattish year over year production next year on my math kind of implies around a 4% decline versus Q4 'twenty levels. I know you guys certainly said that you think about this in a conservative way.
I guess would that end up being a similar shape to what we saw in 'twenty where your production was down a little bit early in the year due to lack of winter fracking and then maybe pick up from there? Just trying to understand the dynamic as to why you'd kind of be down versus 4Q if gas is strong next year?
Yes. We're that's fairly granular to be able to give you the cadence quarter to quarter right now, Leo, I'm sorry. But overall, right now, I'm comfortable just with our outlook being what it is and it's a flat with lower capital in 2021. And the cadence, we do try to manage the cadence and it's a result of just a number of different things, size pads we have, some of the winter season, the expectations on how the market is going to the macro market is going to look. We have not nailed down exactly the cadence for the quarters.
One thing I would say that right now, if you look out in this summer, we had $1.60 gas, dollars 1.70 gas in the, say, the April to October. And if you look out in 2021, if we're even partially right about the lower supply, higher demand running through this winter, then you ought to be able to look out at the period between the April October and say that, that market right now might be about a $2.60 market. So there is, in effect, almost $1 difference during that period of time. So the cadence is still we still have a discussion going internally, but those are some of the things that we look at. Okay.
That's great color. Thank you.
Thanks.
Our next question will come from Charles Meade of Johnson Rice. Please go ahead.
Good morning, Dan, to you and your team there.
Hello, Charles.
Hey, Dan, I wanted to this isn't something you guys really made a point this quarter, but I wondered if you could give us an update on the evolution of your of the Upper Marcellus in your views. And I think the last time you guys really dove into it, we were talking about EURs that were about 90% of what the lower Marcellus is. And so I wonder if you could just give us an update on if that view has evolved anymore and if you have any plans for iterating on that zone or doing some more extensive testing in that zone either in the back half of this year or in 'twenty one?
Yes. And we have drilled some upper wells this year. The number though Charles for comparison between the lower is more 70 plus percent EUR not 90. And that's in our material and that's always been the case. But the wells that we have drilled this year and we've actually drilled uppers on 3 different pads and the wells at in different locations in the field.
And collectively, I'm not going to get granular on it because a couple of wells have been on longer than the other wells that have come on more recently. But collectively, what we have seen is that our type curve on the upper is running slightly above collectively the type curve that we're using as our risk type curve out there in the field for the upper. Do you want
to say
Steve might say something? Yes.
So basically, what Dan is saying is that when you look at those pads currently, they've been on for a short period of time, but they're outperforming our projection for what the type curve would be for in that area. So we're very pleased with those results. Yes.
Got it. That's the kind of color I was looking for. I guess I was misremembering and miscalibrated on that, but thank you for straightening me out. Dan, I recognize that maybe this is a bit of a long shot, but is there anything any comments you would care to make about the case that the Pennsylvania AG uncorked earlier this year with you guys?
Well, the AG has a number of companies have now been recognized by the AG and through their investigations. As you're aware that the charges are, of course, disputed matters, But nonetheless, Cabot is cooperating with the AG, and we have provided his staff with facts and data addressing the allegations directly. We are certainly telling Cabot's side of the story. It's undisputed up there that natural gas is naturally occurring in all the areas of Northeast Pennsylvania. And the methane was up there in the rock prior to the oil and gas industry ever going up there.
When we moved up there, it was a greenfield operation. No drilling had taken place, no production, and there was natural gas in the water systems up there. So we'll continue to work with the AG. We're always employing our best practices to protect the environment and its operations and continue to be a leader in that regard. We do intend to be able to resolve this matter that is positive for all stakeholders.
Thanks for that color, Dan.
Thanks, Charles.
Our next question today will come from Josh Silverstein of Wolfe Research. Please go
ahead. Yes, thanks. Good morning, guys. Just following up on the question before about the upper and the lower Marcellus. You talked about 2 decades of inventory.
I just wanted to see how you could split that right now between the upper versus the lower and at what price deck that would be using? On
our drill cadence, if you look at kind of how we've laid out our long term program and we have shown in a deck in the past, we've shown our production and drilling going out into the 2,040 period. We have go out into the latter part of 2020 decade with our lower drilling and then subsequent to that, we move into the Upper Marcellus drilling. And we have that drilling out into the 2,040 period.
Got it. So it's kind of 10 years for the lower lease as of right now kind of at this maintenance cadence?
It's slightly less, John, than 10 years, but it goes out towards the end of the 2020 decade, yes.
Got you. Okay. And then maybe just talking about that maintenance cadence, one of the benefits of staying at this lower level and not growing is that you can actually lower your base decline rate. I wanted to see where it was at the end of last year, where you think it might be at the end of this year and if you were to just kind of hold things flat where that might be at the end of next year?
Yes, we have our decline rate right now is 29% to 30%. And I don't have the number and Steve Lineman might be able to get me towards the cadence of our decline as he's looked at our reserves towards the end of 2021.
Right. So what you like Dan said, right now, we're kind of running in the 29% to 30% range. As you go out 3 or 4 years and add to the base, we'll probably running in the 25%, 24%, 25% range.
Got it. Understood. Thanks, guys.
And our next question today will come from Kashy Harrison Waugh with Simmons. Please go ahead.
Good morning and thank you for taking my questions.
You bet.
So Dan, you highlighted the 8% free cash flow yield in 2021 at 2.75%. Percent. I was looking at your 2019 financials. It looks like you guys were able to do $1,350,000,000 of discretionary cash flow at about 2.60 I know that had about $150,000,000 of hedge gains, but just doing the simple math there would get you to about $1,200,000,000 And then if I took your the implied CapEx that was discussed earlier in the call, it feels like we should be much higher than 8% at $275,000,000 And so I guess my question is, is that conservatism on your part? Or should we be thinking about basis expansion or maybe cash income taxes as you look toward a higher priced environment?
Yes. I'm going to pitch the ball to Matt.
Hey, Kashy. Yes, I think you nailed it with the cash tax piece. Obviously, last year, we also had the benefit of higher significantly higher deferred tax add back because of some tax reform, etcetera. So as we move forward, now that we've maximized all the utilization of our NOLs and AMT, we're just not going to see those same tax benefits in the future. And I'd add, Rich, there's always conservatism in our guide as well, as you know.
Got it. Very helpful. I guess, those high class problems. And then as you think about capital spending or as you look at your capital spending or as I was looking at your capital spending, it seems like you guys have spent just under 60% of the budget, but you've completed well over that proportion of your targeted wells for the year. And so I guess my follow-up question was, are you guys seeing some sort of some efficiencies or cost improvements?
And is there anything to read through for implications to the full year budget? Or is this just more so timing related?
We have efficiencies in our program. We decided to maintain our $575,000,000 CapEx. It's mid year right now. It might be a conservative position, but we wanted the least noise in the release as we could deliver and we thought that was appropriate.
That's very helpful. And if I could just sneak one more in and just follow-up on some earlier questions on the Upper Marcellus. I was just wondering, I know we've always talked about the 70% of the upper 70% of the lower on the well performance front. Have you guys ever talked about just how to think about the difference in well costs between the two zones?
Well, we haven't we've talked about it maybe more indirectly, but we have made comments regarding our full development case of our Upper Marcellus. And to not make this a long winded answer, Scott has told me sometimes that I talk too long on my answers. But when you look at the full development of the Marcellus, you can really Upper Marcellus, you can really look at the Upper Marcellus as a blank piece of paper for the most part. We intend to, particularly with the legislation that has been passed recently about longer laterals and how you drill within or across units, it is our intent to lay out the sticks for the Upper Marcellus with longer laterals on average than we've been able to drill in the Lower Marcellus program. With the drilling of the longer laterals, and I'm talking about kind of the 12,000 foot type laterals in the Upper Marcellus, there's efficiencies inherent in drilling longer laterals than shorter laterals.
With our currently, even in the lower, in our longer laterals, if we drill 11,000 or 12,000 foot laterals and you look at our completion efficiencies or some represent their the cost of development in what the cost is per foot. And in our even in our lower, we have a say a 700 slightly over 700 dollars per foot cost in our 11,000 foot type of lateral that we drill in the lower. And we have those as actual costs that we have seen in 1st and second quarter of this year. There's another thing on the efficiencies that we see in those in that cost, Cabot also loads in of our cost per foot. We also load in our all our facilities in that cost and we load in all the construction associated with our pad sites into those costs.
That is, again, all in cost for us. And the other thing we do is we have what we think are very efficient completions. We have £2,500 of profit we use in our completions versus I know some other companies might use less proppant. So their cost for proppant is going to be maybe slightly less than ours. But we do like the amount of gas that we have coming out of our wells.
And so our recipe, we think, we have dialed in is very efficient. So there is going to be overall considerably less cost attached to the development of our Upper Marcellus, including use of roads, reuse of pad sites, we hope reuse of some of the equipment. So we would take even though it might be a 70 plus percent comparison to the lower, we think on a return profile basis because of what I'm just mentioning, our upper development is going to be an extremely good return profile.
That's excellent color. Thanks for all that.
Ladies and gentlemen, this will conclude our question and answer session. At this time, I'd like to turn the conference back to Dan Dinges for any closing remarks.
Thank you, Allison. And once again, I would just like to say thanks again to those dedicated shareholders of Cabot's, but also a debt of gratitude to Cabot's team. They have been out there through this very difficult environment. Many of our field operators have been going to work every single day, even though some of the corporate headquarters and office in Pittsburgh have honored the stay at home edicts because of this pandemic. But those guys and girls out there in the field have gotten up every day to head out and do the work.
And as you can see by our numbers, we've been able to deliver on our program, and I'm very proud of the group. So thanks again for the attention. Look forward to next quarter's call. Thank you.
The conference has now concluded. We thank you for attending today's presentation and you may now disconnect your line.