Goodrich Petroleum Corporation
Q1 2020 Earnings Call Transcript

Published: 10 May 2020

[Operator:]

Good day, and welcome to the Goodrich Petroleum First Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions]. Please note this event is being recorded.I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead, sir.

[Walter Goodrich:]

Thank you, Cole. Good morning, everyone. Thank you for participating in our first quarter 2020 earnings call this morning. Like almost everyone else in the world, we have adapted and adjusted our procedures and protocols in response to the COVID-19 lockdown. We have successfully managed through the past couple of months with little to no impact on our operations or performance.In addition, our Haynesville Shale natural gas focused strategy and hedge position has almost completely protected us from the recent crash in crude oil prices, with our first quarter production mix being 98% natural gas and approximately 60% of our first quarter crude oil production protected by hedges at approximately $60 per barrel.We are seeing the impact of the crude oil sell off, including dramatic reductions in oil-directed rig count activity as well as crude shut-ins, which are reducing the amount of forecasted associated natural gas production. This in turn has resulted in significant improvement in the forward-looking strip prices for natural gas since we last reported to you in early March, with calendar year 2021 strip prices now trading at approximately $2.70 per Mcf.At the same time, the steep decline in rig count is leading to materially lower bids for goods and services across the board, including rig, pipe and frac spread rates, which cumulatively are reducing our average forecasted completed well cost by approximately 15% to 20%.The combination of the lower CapEx cost and improving natural gas strip prices have us encouraged and expecting we will be achieving even more compelling returns on our capital in the second half of the year and into 2021.Currently, we're in the process of releasing the rig we have had under contract and plan to take an approximate 2-month break before resuming drilling operations again. This schedule is part of our overall strategy and plan to remain in maintenance CapEx mode designed to keep production levels roughly flat while generating significant free cash flow.While this is our current plan, we maintain the flexibility to increase activity levels and resume a higher rate of growth at such time as market conditions dictate and our Board of Directors believes that, that is the best way to provide the best return for our shareholders.We have again prepared a slide presentation and we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on our website at goodrichpetroleum.com and see entitled under Presentations 1Q 2020 Earnings Presentation. I will now turn to the slide presentation for those of you who would like to follow along, and our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2.On Slide 3, we provide you with certain specific data regarding our environmental, social and governance statistics. We plan to continue to share this information with you as well as to update and refine as conditions and best practices evolve over time.On Slide 4, we have again included an overview of the company and our assets, which highlights our core Haynesville Shale position in Northwest Louisiana, where our inventory life currently stands at approximately 16 years. Our Northwest Louisiana Haynesville inventory alone contains over 1 Tcf of natural gas resource potential, where both company and industry development has de-risked our position.The company's total net production grew by 32% compared to the first quarter of 2019 and down slightly sequentially to an average of 137 million cubic feet of natural gas and equivalents per day in the first quarter as we tried to maintain roughly flat production quarter-over-quarter.We expect quarterly production may fluctuate based on the timing and completion cadence as we add wells which typically have relatively high working interest and very robust early time production levels.Performance from our refined completion designs has led to average reserves per 1,000 feet of lateral of 2.5 Bcf, which coupled with lower CapEx and very low LLE are already attractive rates return or on track to get even better.We're calculating and updating each quarter our return on capital employed or ROCE, which was approximately 12.5% in the first quarter.Despite very weak natural gas prices in the first quarter, where we had realized prices of $1.73 per Mcf, and roughly flat production volumes, we nevertheless reported EBITDA for the quarter of $16.6 million.Moving to Slide 5, we show our year-end 2019 SEC proved reserves of 517 Bcfe, which has a present value of just under $300 million using SEC mandated pricing and discounted at 10%. As you'll see from the pie chart, our proved reserves are almost exclusively natural gas and associated with our core Haynesville Shale position.On Slide 6, we have updated our cap table as of the end of the first quarter. As of the end of the quarter, we have total net debt of $106 million and approximately $93 million outstanding under the senior credit facility, which is the same amount that was outstanding as of the end of last year.Our bank group has recently completed our spring borrowing base redetermination, which resulted in a slight 4% reduction from $125 million to $120 million due to the reduction in natural gas prices.In addition, we were able to extend the maturity of our second lien notes from May of 2021 to May of 2022 with no other changes to the terms and conditions of the notes. The balance sheet remains in very good shape with net debt-to-EBITDA at the end of the first quarter of just 1.3 times.On Slide 7, we show our annual growth and net production volumes over the past several years, including the midpoint of our guidance for 2020 of approximately 140 million cubic feet per day. As I've said, our current strategy and goal is to roughly maintain current production levels for the balance of this year with a significantly reduced CapEx program.Moving to Slide 8. We have updated our hedging summary, which shows the volumes, type and prices of our current natural gas and crude oil hedge positions. As I mentioned on our last quarterly call, we are watching the markets very closely and routinely evaluating our hedge position. Our position continues to provide us excellent protection from the current low prices and delivered $9.1 million in gain in the first quarter, of which $6 million was a realized gain in cash receipts.As you can see, we are well hedged throughout the balance of this year with a combined 70 million cubic feet of gas hedged with a blended average floor price of $2.60 per Mcf.In addition, we recently took advantage of the significant improvement in the longer term strip prices for natural gas by adding to our calendar year 2021 and early 2022 positions. With the recent hedging additions, we now have approximately 40% of our current production levels hedged throughout 2021 at a blended average price of approximately $2.55.While we expect natural gas prices to improve from here, we believe the current hedge position is prudent and provides appropriate downside and risk mitigation for our shareholders.Finally, we provide details of our current 2020 guidance on Slide 9, which, as I've said, provides a roughly flat production profile with a focus on free cash flow generation on a CapEx program with a midpoint of approximately $45 million.You'll see that our 2020 plans will be heavily weighted to the Bethany-Longstreet position, where we've had great success in our drilling operations and well performance. While we will drill a combination of 4,600, 7,500 and 10,000 foot Haynesville laterals, our estimated blended average lateral length for 2020 is approximately 8,500 feet.We've also updated our guidance for expected bases differentials in the Haynesville as well as estimates for our 2020 per unit cash cost per Mcfe. In addition, we provide the anticipated well count and completion cadence on a quarterly basis for your review.And with that, I'll turn the call over to Rob.

[Robert Turnham:]

Thanks, Gil. Revenues adjusted for cash settled derivatives totaled $29 million, comprised of $23 million of oil and natural gas revenues and $6 million cash settled derivatives. Average realized price, including cash settled derivatives was $2.32 per Mcfe for the quarter versus $2.53 in the previous quarter. Average realized price without the hedges was $1.84 per Mcfe in the quarter.Our per unit cash operating expense, which is defined as operating expenses excluding DD&A and noncash G&A, was $1.03 per Mcfe, generating a cash margin of 58% for the quarter.Capital expenditures for the quarter totaled $18.4 million, of which 99% was spent on drilling and completion cost associated with Haynesville wells. We conducted drilling operations on 12 gross, 4.0 net wells and added 5 gross, 1.8 net wells in the quarter. Of the 5 gross, 1.8 net wells added in the quarter, 1 gross and 1 net operated well were added in January and 4 gross, 0.8 net non-operated wells were added at the end of March, which had previously been modeled in the second quarter. We exit the quarter with 10 gross, 4.6 net drilled but uncompleted wells, for completion at a later date, which should be at higher prices.We reaffirm our previous guidance of $40 million to $50 million of CapEx for 2020 and are now planning to complete and turn in line just short of an additional net well versus pervious guidance.Interest expense totaled $2 million in the quarter, which included cash interest of $1.2 million incurred on the company's revolver and noncash interest of $0.8 million incurred on the company's convertible notes. The noncash interest expense was comprised of $0.4 million of paid-in-kind interest and $0.4 million of amortization of debt discount and debt issuance cost primarily associated with the company's second lien notes.Moving back to our slide deck. As we've highlighted before, we've included several slides, beginning with Slide 10, that show how we compare to our peers.As stated earlier and as you will see again on Slide 10, our trailing 12-months return on capital employed was 12.5% despite very low commodity prices in the quarter. This 12.5% return ranks fifth out of the 52 companies in our peer group even though we are calculating through the first quarter with much lower commodity prices than the peer group, which calculation was made for them on a trailing 12-months basis through the fourth quarter when prices were higher. Our guess is we will move even higher in the ranking once our peer companies have been updated through the first quarter.In addition to returns, it is critical to maintain low leverage in these challenging times for commodity prices, and as we said earlier, we sit at 1.3x trailing 12-months EBITDA, as shown on Slide 11.Even though our capital efficiency and return on capital employed are near the top of the peer group and our debt-to-EBITDA is conservative, we only trade at a little over 2x enterprise value-to-EBITDA, as shown on Slide 12, even after a nice move up recently.Needless to say, it is an extremely low multiple versus where companies typically trade, in particular one with low debt metrics in an improving commodity market with exceptional rates of return. As our average daily volume over the last 45 days has ticked up, we're hopeful we will see more institutional interest in the stock, in particular when viewing our leverage to an improving natural gas price and decreasing service cost environment.And although we won't establish 2021 guidance until late this year, our internal modeling suggests at current strip pricing, including our hedges, we potentially could hold volumes flat and increase EBITDA about 15% to 25% with 15% to 25% less capital based on current cost estimates. This is obviously preliminary and subject to change, but sets up nicely if prices materialize consistent with the curve.As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville, beginning on Slides 13 and 14.We currently have over 22,000 net acres in the core of the play and we entered 2020 with 208 gross, 91 net locations on spacing of 880 feet between well bores for a net inventory life of over 16 years at current pace. Our acreage in North Louisiana is over 70% undeveloped and 73% operated. We estimate over 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral and 80-foot spacing in North Louisiana alone versus year-end '19 proved reserves in North Louisiana of approximately 510 Bcf equivalent.We also maintain approximately 30,000 net acres held by production in the Angelina River Trend of the Shelby Trough, where you saw a recent development transaction announced by Black Stone Minerals. The Haynesville and Bossier formation are both perspective on our Shelby Trough, Angelina River Trend acreage. The evolution of the completion design in the Haynesville that was shown on Slide 15 has transformed the play into one of 2 premier gas basins in the country.Our results, as shown on Slide 16, are very consistent. All of our acreage has now been de-risked and we're in development mode drilling predictable wells and proven areas and connecting wells into existing pipes with excess capacity.We continue to outperform our type curves, and on Slide 17, we track our wells versus 309, 4,600 foot lateral industry wells drilled in the core. Industry pumped an average of 3,100 pounds per foot, but as you can see, the older wells are underperforming the newer wells as average proppant is lower on those older wells.Our 6 wells, shown in green, were stimulated with approximately 4,100 pounds per foot of proppant and tighter clustering and interval spacing, and not only are they quite a bit better than the industry average composite curve, our wells exceed our 2.5 Bcf per 1,000-foot type curve to an estimate of approximately 2.7 Bcf per 1,000 feet. There is a clear correlation between proppant loading and cluster and interval spacing, and we expect our more recent wells to pull up the composite curve over time from this optimization.Slide 18 reflects our 7,500 foot curve, where we now show a composite of 225 industry wells with an average proppant concentration of approximately 3,000 pounds per foot, which for the most part fits our 2.5 Bcf per 1,000-foot type curve.The older wells included in the industry composite curve that are underperforming the curve in the later year are a handful of under stimulated wells with proppant loading of approximately 2,300 pounds per foot.Like the 4,600 foot laterals, our more recent operated 7,500 foot wells are outperforming materially to a composite estimate of approximately 2.8 Bcf per 1,000 feet due to higher proppant concentration and tighter cluster and frac interval spacing.Slide 19, which now shows a composite result from 225, 10,000 foot laterals with an average of 3,000 pounds per foot of proppant are for the most part tracking our 2.5 Bcf per 1,000-foot type curve until the older wells with lower proppant concentration kick in a little over 2 years out.Our 9 wells, which average approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant, are for the most part tracking our 2.5 Bcf per 1,000-foot curve.As we have stated before, we believe our well performance speaks for itself and is driven by a number of factors

[Operator:]

[Operator Instructions] And our first question today comes from Welles Fitzpatrick from SunTrust. Please go ahead.

[Welles Fitzpatrick:]

Hey, good morning.

[Robert Turnham:]

Good morning, Welles.

[Welles Fitzpatrick:]

Just a housekeeping question. The 15% to 20% reduction in cost that you guys talk about, can you remind me, is that included in guidance or would that be incremental to it?

[Robert Turnham:]

Yes. So I've tried to address a little bit of that in the prepared remarks, Welles. And this is Rob. We're completing an extra -- almost an extra net well with the same CapEx guidance. We haven't changed our production guidance. Obviously, a little bit more completion activity could improve on that. But for now, we're staying with the midpoint of our guidance at $140 million a day. And there's potentially room to come in on the lower portion of our CapEx range. So for now, we've kept the range the same, but are increasing by -- it's really 0.8 net wells versus previous guidance.

[Welles Fitzpatrick:]

Okay, okay. Perfect. And sorry again if you guys hit on this, but what trends are you seeing on the non-spending side and how do you think that could flow through to the 2020 spend?

[Robert Turnham:]

Yes, exactly. So the 4 gross, 0.8 net wells that were added at the end of March, we had previously guided for that in the second quarter and they completed them sooner than that and those were all non-operated wells. So it's a great question, what do we see from a non-op standpoint?For the rest of this year, we really don't currently budget or don't have included in our guidance non-operated wells that could change down the road in the future, but we think it would be more likely that it would be in the back -- call it the last quarter and a half if that occurs. We don't think we're going to see any Chesapeake well proposals. But we have smaller interest in some other areas that potentially could be developed late this year.But again, right now, it's not definitive. We haven't baked that into our guidance and we haven't formally elected into any proposals.

[Welles Fitzpatrick:]

Okay, okay. Perfect. And then just a last one from me. When you talk to those 4.6 DUCs, is there -- I mean is there a trigger price in mind? Is it timing? And if it's price, like I think it sounded like, could you give us some idea of what might get you guys to get the fleets out there?

[Robert Turnham:]

Yes. Well, so when you look at our cadence, some of those DUCs are clearly baked into that cadence. So when people say, "Hey, your CapEx ran hot in the first quarter," it was really capturing the cost that we had all along planned. We thought it would be smoothed out a little bit more into the second quarter, but it was capturing it in the first quarter and the cadence factors in some of those DUCs.Now we do currently have an incremental well or 2 that we're currently scheduling to complete in January of 2021 that would not be included in that schedule. So I think based on -- holding volume was relatively flat, like Gil said. Seeing an improving gas price later this year, I think if you forecasted relatively flat volumes quarter-over-quarter with some variants based on when you complete those wells, then that probably still makes some sense. So partly it's just better gas prices in the future, but secondarily it's trying to hold volumes flat and maintaining those DUCs such that you could complete them to accomplish your maintenance program.

[Welles Fitzpatrick:]

Okay, perfect. Thank you, guys so much.

[Robert Turnham:]

Thanks, Well.

[Operator:]

And our next question comes from Dunn McIntosh from Johnson Rice. Please go ahead.

[Unidentified Analyst:]

Hi. Good morning, Rob and Gil. This is actually Austin, his associate. Congrats on another strong quarter.

[Robert Turnham:]

Thank you.

[Unidentified Analyst:]

I guess my first question is, the new presentation highlights some significant service cost reductions. I was wondering if you were hearing -- what you all were hearing from those providers and is it largely driven by a lack of demand in the oil basins. And is it -- are other contracts primarily batch to batch or do you have the ability to lock in longer term contracts?

[Walter Goodrich:]

Yes. So a couple of good questions there. Yes, obviously, what we're seeing here recently is largely being driven by the crude oil sell off and the steep drop in overall rig counts, which obviously has been more pronounced -- much more pronounced in the oil side versus the gas directed side. So we are getting the benefit in that regard.In terms of the rigs, obviously, the rigs being turned back at the rate that they have, people are cutting their costs pretty dramatically to be able to either keep them working or have someone pick them up. So as a benchmark, you're looking at rig rates that 3 or 4 months ago were probably in the range of $20,000 a day, that today are more in the range of $15,000 to $16,000 a day. So that gives you an idea of some of the costs.And then the other big one is really on the frac side, and we're seeing just incredibly impressive numbers coming in on frac spread rates going forward and obviously that's also due to the stacking of tremendous numbers of frac fleets from the oil sell off. So I think you would say that that's been a factor, the early spring weakness in natural gas prices has been a factor. And fortunately, we're now seeing a chance to take advantage of that.In terms of longer term nature, we could lock some stuff down, particularly in terms of the drilling rig. A little bit more difficult in some of the other areas. And given our level of activity, it's a little more challenging to really lock something down, say, through the balance of this year. But we're managing that as best we can.

[Unidentified Analyst:]

I appreciate the commentary. And I guess my follow up question you kind of touched on it with Welles' answer. But it looks like the extra completion in 1Q and as you said, I believe the full year '20 CapEx was unchanged. And so is that mainly driven by lower costs or is that driven by line of sight on further reductions? And it looks like -- sorry, 3Q will be the heaviest on completions and no completions in 4Q. Is that angled towards bringing on new volumes in what looks like a much stronger price?

[Walter Goodrich:]

Yes. So I'll take that. I mean basically it's I guess something -- on the non-op piece, there's some things that we can't control the timing of, so we make the best estimates we can. Secondarily, we've designed the cadence to try to keep production volumes as roughly flat as we can quarter-over-quarter. We did have a little bit of waiting obviously to the frontend of the 2020 period. We do have a good bit of activity planned in the third quarter, which will roll into the fourth quarter volumes, where we think we'll be taking advantage of better pricing.So a little bit of all of those, but generally trying to keep production volumes flat and generate as much free cash flow in the calendar year period as possible.

[Unidentified Analyst:]

Thank you.

[Operator:]

And our next question comes from Jeff Grampp from Northland. Please go ahead.

[Jeffrey Grampp:]

Good morning, guys.

[Robert Turnham:]

Good morning, Jeff.

[Jeffrey Grampp:]

Rob, I think you mentioned in the prepared remarks, it sounded like some pretty impressive cash flow growth with less capital in '21 without even really needing to do anything to the volumes. But given kind of the bullishness it sounds like there is here internally and externally with natural gas prices, what would you guys say is kind of that trigger point to get you to do something maybe a little bit more aggressive than a maintenance level program? And then kind of a related point, is there any comfort level internally into an out spend for growth? Or would any growth need to be kind of within a cash flow type of model?

[Walter Goodrich:]

Yes. So Jeff, great question and you hit right on what I was trying to state, even though we haven't put formal guidance out there and it's subject to the Board approval and change. It's the ability to do more with less. And obviously to hold volumes flat and spend 15% to 20% less, creates that much more free cash flow.And so every time we drill a well, in particular at these rates of return and what you'll see in our economics, that at $2.75 gas, which is really where the strip basically is, all 3 laterals at current service cost generate over 100% IRR. And so going to be a very compelling reason in my mind to not just hold volumes flat, to go ahead and spend more money, even if you spent the same amount of money in 2021 versus 2020, you're going to see pretty healthy growth and a pretty dramatic increase in the value of your PDP reserves. And frankly, you're going to grow your EBITDA. And you're going to have to trade at a better price just -- even if you held your multiple the same.So we'll see where we are as we get closer to the end of the year. We usually put that budget out in December. But as we've said before, we said it in this press release, the ability to spend a little bit more money and yet still generate free cash flow, grow the enterprise that much faster. And we're not talking about just volumes, we're talking about value here. The value of your PDP reserves at a minimum is certainly on the table. And we'll just have to see where we get there -- when we get there and what the Board's decision might be.But with over 16 years of inventory life what's really interesting

[Jeffrey Grampp:]

Got it. No, that's perfect. I appreciate it. For my follow up, you guys are extending the term on the second lien for a year. Is there how should we think about that in terms of being a functional piece of the balance sheet? Is that -- was that -- I guess should we think about the intent of that to remain on the balance sheet maybe a little bit closer to that term? Or was that I guess more of a flexibility maneuver such that you don't have to do anything...

[Robert Turnham:]

I think we don't think of it as a permanent significant piece of the balance sheet. It's there because we wanted to have as much liquidity under the revolver as possible. As we go through a fall and then a spring of '21 redetermination, to the extent that we see significant amounts of increasing liquidity under the revolver, it's highly possible -- it's not likely that sometime in the 2021 probably not this year, but sometime next year that we would pay that off.

[Jeffrey Grampp:]

Go it. Understood. Appreciate the comment, guys.

[Robert Turnham:]

Thanks, Jeff.

[Operator:]

[Operator Instructions] And our next question comes from Noel Parks from Coker & Palmer. Please go ahead.

[Noel Parks:]

Good morning.

[Robert Turnham:]

Good morning, Noel.

[Noel Parks:]

I just wanted to make sure I had a number right. When you were saying before -- I think I got this right, about field level IRRs due to the recent reduction in costs were up to -- I think you said the 60% to 98% range, I was trying to spot that in the slides. Was that from Slide 20?

[Robert Turnham:]

Yes. So if you look at -- and it's 20 through 22. And I believe I said it, even at $2.25 we could generate 60%, close to 100% -- 60% to almost 100% IRRs. In particular on Slide 21, the 7,500 foot lateral at $2.25 generates 97.5%. So that was the comment.

[Noel Parks:]

Great. Thanks a lot. I just want to make sure I had the source right on that. And the discussion, of course, about the services side has been interesting and helpful, sort of especially making me think more about the interplay between what happened in the oil side and how that can have sort of feedback into the services for you. And I guess just as a little bit of a reality check, have you seen a migration of service vendors over the last month or 2 or of equipment either -- I could sort of picture it either coming in the bay area just on gas looking stronger, or maybe just being taken out of commission all together, and so maybe the total amount of equipment sort of going down. Do you have any sense of that at this point?

[Walter Goodrich:]

Yes. Noel, this is Gil. We don't really have a whole lot of great intelligence on what kind of increases may have incurred in the Haynesville area specifically, but we know from a vendor perspective as their overall fleets are getting largely stacked, they've got to become more competitive in order to keep what they do have working, working.And so as I said I think a minute ago, we did go through a pretty weak spring. In fact, current top months are quite weak as well and kind of a $2 or slightly sub $2 number. And that has seen overall Haynesville rig counts slowly coming down over the last 6 months or so. So we peaked at about 60 rigs running in the Haynesville kind of mid-year last year. We're down in the kind of mid to high 30 rigs running currently. And those things have also contributed to the improvement in prices. And then we've had an acceleration of that here with the oil price crash. Whether or not companies are moving additional equipment into the Haynesville, I really can't say at this point in time.

[Noel Parks:]

Okay. Great. That's helpful. And I think most of -- I did also -- just to follow up a little bit on DUCs. So it does sound like that really does give you some flexibility going forward. And actually, I had a different question. I wanted to ask, from what we're hearing from the public folks in the Haynesville just sort of how you're approaching the price environment, as best you can tell, is the behavior pretty similar among the private folks out there as well in Haynesville?

[Robert Turnham:]

Well, I'll take a stab at that, Noel. This is Rob. There are actually some private guys who are probably spending more money than the public guys on an equivalent basis mainly because of funding and highly percentage of gas hedged at good prices. So even though the rig count has fallen pretty dramatically, as Gil pointed out, you do see the rig count being probably higher than it would had those hedges not been in place.Now the question is

[Noel Parks:]

Right. And actually talking about prices and the futures curve, I haven't paid a ton of attention to it. I guess it wasn't all that encouraging until recently. Do you have any sense sort of what the liquidity is looking out -- looking like as you go a bit further out the futures curve? My just -- my casual observation suggests to me that the volume hasn't been all that high just considering we're at the best levels we've been in a while.

[Robert Turnham:]

Sure, Noel. And yes, it's a valid point. Anytime -- the further out you go, the less liquidity there is in the market and the wider the bid-ask spread is on swaps, if you want to try to hedge those volumes. We've always just gone out 18 months or so and there's been plenty of liquidity and transparency and good pricing over that term certainly.But yes, it's just like E&P equity research. There's fewer hedge funds speculating in commodity prices in the futures curve. That being said, there's some sell side firms out there who are very smart guys that are known to be ahead of the industry who are predicting $3 to $3.50 gas in 2021. They came out when gas prices for 2021 were a good bit lower and the market has moved in their direction.So we're not here to predict gas prices. We've -- no one knows for sure. But we certainly rely on a lot of smart guys who are very bullish on 2021. And how could you not be with shut-ins of the world and associated gas reduction in CapEx programs? And obviously, we've got to get to the other side of the virus and get the LNG export demand at 100%. But it sure feels better looking forward than it has been in a long time.

[Noel Parks:]

Great. Thanks a lot.

[Robert Turnham:]

Thanks, Noel.

[Operator:]

And this will conclude our question-and-answer session. I'd like to turn the conference back over to you, Gil Goodrich, for any closing remarks.

[Walter Goodrich:]

Thank you, everyone. I appreciate you participating in our first quarter call. We look forward to reporting 2Q to you in a few months. Thank you.

[Operator:]

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines at this time and have a great day.