Q1 2020 Earnings Call

May 7, 2020

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Ladies and gentlemen, today's call is scheduled to begin shortly until that time your lines will again be placed on music cold.

Operator: Ladies and gentlemen, thank you for standing by, and welcome to the Q1 2020 Comstock Resources, Inc. Earnings Conference Call. At this time, all participant lines are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and Chief Executive Officer. Please go ahead.

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[laughter].

And gentlemen, thank you for standing by and welcome to the Q1 20, Comstock resources Inc. earnings Conference call. At this time all lines all participant lines or were they listen only mode. After the speakers presentation. There will be a question and answer session to ask a question. During the session. You want me to press Star one on your telephone please be advised.

So today's conference is being recorded if you require further assistance. Please press star zero.

I'd now like to hand, the conference over to your Speaker today, Jay Allison Chairman and Chief Executive Officer. Please go ahead.

M. Jay Allison: Tina, thank you, and good morning, everyone. We know it's a crowded morning. The docket is crowded. Lots of earnings reports came out last night, and this is a prime-time slot. Those of you that are participating right now, thank you. I have a few comments before we start the formal presentation. The last 60 days has stress-tested every business in the world, especially the oil and gas business. We, as an industry, are managing the ripple effect of the initial increased oil supply from the Saudi Arabia-Russian oil feud, which has been dialed back as of this month, coupled with the coronavirus pandemic that has reduced the demand for oil by 25% to 30%.

Hi, Tina Thank you and.

Jay Allison: Tina, thank you, and good morning, everyone. We know it's a crowded morning. The docket is crowded. Lots of earnings reports came out last night, and this is a prime-time slot. Those of you that are participating right now, thank you. I have a few comments before we start the formal presentation. The last 60 days has stress-tested every business in the world, especially the oil and gas business. We, as an industry, are managing the ripple effect of the initial increased oil supply from the Saudi Arabia-Russian oil feud, which has been dialed back as of this month, coupled with the coronavirus pandemic that has reduced the demand for oil by 25% to 30%.

Good morning, everyone. We know what's your crowded mornings. The docket is crowded lots of earnings reports came out last night.

And this is a prime time slots. So does the view that are participating right now thank you.

Few comments before we start the formal presentation.

The last 60 days as stress test every business for the world, especially as you want to gas business. We as an industry are managing to ripple effect to the initial increased oil supply from the Saudi Arabia, Russian oil fuel, which has been down back as of this month, coupled with the Corona virus pandemic that has.

Dave just the demand for oil led by 25% to 30%.

M. Jay Allison: Fortunately, however, Comstock is 98% natural gas, has an industry-leading low-cost structure in the Haynesville, has industry-leading high margins, has hedged almost half the production expected for the next 12 months, and has meaningful free cash flow. Since we are 98% natural gas, we have already become a beneficiary of the corrected oil market as we see associated gas being shut in and a collapse in the rig count occurring. Roland Burns, our CFO, will report our strong Q1 results, and Dan Harrison, our COO, will tell you why our costs are down and should continue to be lower in the months ahead. Our numbers are solid because of our consistent stellar well results and the location of our natural gas fields being in proximity to the Gulf Coast market.

Jay Allison: Fortunately, however, Comstock is 98% natural gas, has an industry-leading low-cost structure in the Haynesville, has industry-leading high margins, has hedged almost half the production expected for the next 12 months, and has meaningful free cash flow. Since we are 98% natural gas, we have already become a beneficiary of the corrected oil market as we see associated gas being shut in and a collapse in the rig count occurring. Roland Burns, our CFO, will report our strong Q1 results, and Dan Harrison, our COO, will tell you why our costs are down and should continue to be lower in the months ahead. Our numbers are solid because of our consistent stellar well results and the location of our natural gas fields being in proximity to the Gulf Coast market.

Fortunately, however, comstock is 98% natural gas as an industry, leading low cost structure in the Haynesville is industry, leading have margins have changed almost half the production expected for the next 12 months and has meaningful free cash flow.

Since we are 98% natural gas, we've already become a beneficiary yet because the corrected oil market as we see associated gas being shut in and I collapse in the rig count occurring Roland Burns our CFO report our strong first quarter results and then Harrison our COO will tell you why our cost her.

Down there and should continue to be lower in a bunch ahead. Our numbers are solid did because of our consistent stellar well results and the location of our natural gas bills being your proximity to the Gulf Coast market. There's I report from the 270 employees that Comstock that made this quarter successful.

M. Jay Allison: Here's our report from the 207 employees at Comstock that made this quarter successful, even in a very difficult energy environment. Welcome to the Comstock Resources Q1 2020 Financial and Operating Results Conference Call. Today, we'll review our Q1 2020 earnings and drilling results. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled Q1 2020 Results. I have Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws.

Jay Allison: Here's our report from the 207 employees at Comstock that made this quarter successful, even in a very difficult energy environment. Welcome to the Comstock Resources Q1 2020 Financial and Operating Results Conference Call. Today, we'll review our Q1 2020 earnings and drilling results. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled Q1 2020 Results. I have Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws.

Even in a very difficult energy environment.

Welcome to the Comstock resources first quarter 2020 financial and operating results Conference call. Today will review, our first quarter 2020 earnings and drilling results you can view a slide presentation during or after this call by going through our website at www Dot Comstock resources, dotcom and downloading the quarterly.

Result presentation, there you'll find a presentation entitled first quarter 22 Warner results.

I have Jay Allison Chief Executive Officer, Comstock to with me as Roland Burns.

President and Chief Financial Officer, Dan Harrison, our Chief operating Officer, and Ron Mills, our VP of finance and Investor Relations. Please refer to slides two and our presentation to note that our discussion today will include forward looking statements within the meaning of securities laws, well, we believe the expectations and stuff such Davis.

M. Jay Allison: While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if you'll turn over to slide three. On slide three, we cover some of the highlights for Q1. Most importantly, our natural gas operations in North Louisiana and East Texas have not been adversely impacted by the COVID-19 virus pandemic that has disrupted all of our lives. We've been able to maintain our normal operating activity and adjusted our processes to create a safe work environment for our employees and contractors. The collapse in oil prices will impact our oil properties in the Bakken and Eagle Ford, but have inversely had a positive impact on natural gas prices. We feel that the reduced activity in both gas and oil-directed drilling will create a healthy balance between supply and demand for natural gas.

Jay Allison: While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if you'll turn over to slide three. On slide three, we cover some of the highlights for Q1. Most importantly, our natural gas operations in North Louisiana and East Texas have not been adversely impacted by the COVID-19 virus pandemic that has disrupted all of our lives.

Pretty reasonable there could be no assurance that such expectations will prove to be correct.

Now if you'll turn over to slide three.

On slide three would cover some of the highlights for the first quarter. Most importantly, our natural gas operations in north ways, Yes, and East Texas.

Have not been adversely impacted by the Kobe 19 virus pandemic that has disrupted all of our lives we've been able to maintain our normal operating activity and adjusted our processes to create a safe work environment for our employees and contractors they will.

Jay Allison: We've been able to maintain our normal operating activity and adjusted our processes to create a safe work environment for our employees and contractors. The collapse in oil prices will impact our oil properties in the Bakken and Eagle Ford, but have inversely had a positive impact on natural gas prices. We feel that the reduced activity in both gas and oil-directed drilling will create a healthy balance between supply and demand for natural gas.

Lapse in oil prices will impact our oil properties in the Bakken and Eagle Ford, but have inversely you had a positive impactful natural gas prices, we feel that to reduce activity in both gas and oil directed drilling will create a healthy balance between supply demand for natural gas the one state but that is remain.

M. Jay Allison: The one statement that has remained very consistent is that our Haynesville-Bossier Shale drilling program continues to deliver strong results. Comstock and Covey Park had drilled and completed a combined 237 operated wells since 2015, which had an average IP rate of 23 million cubic feet per day equivalent per day. We have drilled more than any other operator in the play during this period. Our drilling activity drove the 27% year-over-year growth from our Haynesville-Bossier property since the Q1 of last year on a combined basis. We have also been driving down our well cost in the same period. The Q1 well costs per lateral foot are 15% lower than what we averaged in the Q1 of 2019. Recent well costs have improved even further.

Jay Allison: The one statement that has remained very consistent is that our Haynesville-Bossier Shale drilling program continues to deliver strong results. Comstock and Covey Park had drilled and completed a combined 237 operated wells since 2015, which had an average IP rate of 23 million cubic feet per day equivalent per day. We have drilled more than any other operator in the play during this period. Our drilling activity drove the 27% year-over-year growth from our Haynesville-Bossier property since the Q1 of last year on a combined basis. We have also been driving down our well cost in the same period. The Q1 well costs per lateral foot are 15% lower than what we averaged in the Q1 of 2019. Recent well costs have improved even further.

Okay, very consistent is that our haynesville bugs or shale drilling program continues to deliver strong results Tom Shaw Covey Park at drilled and completed a combined 237 operated wells since 2015, which had an average pay rate of 23 million cubic day equivalent.

Today, we have drilled more than any other operator in the play during this period.

Drilling activity drove the 27% year over year growth from our Haynesville Bolger properties since the first quarter of last year on a combined basis. We have also been driving down our well cost and the same period, the first quarter, well cost per lateral foot or 15% lower than what we averaged in the.

First quarter 2019 ratio well cost have improved gave them further we expect our well cost to average $1100 per completed lateral foot in 2020.

M. Jay Allison: We expect our well costs to average $1,100 per completed lateral foot in 2020. The strong natural gas production growth this quarter was offset by weak natural gas prices in the first quarter. For the quarter, we reported oil and gas sales of $271 million, which is a 105% increase over Q1 2019. We had adjusted EBITDAX of $202 million, up 108% over Q1 2019. We also reported operating cash flow of $156 million, up 120% over Q1 2019, or $0.55 per share, and adjusted net income for the quarter of $24 million or $0.12 per share. Now I'll have Roland cover the financial results in more detail. Roland?

Jay Allison: We expect our well costs to average $1,100 per completed lateral foot in 2020. The strong natural gas production growth this quarter was offset by weak natural gas prices in the first quarter. For the quarter, we reported oil and gas sales of $271 million, which is a 105% increase over Q1 2019. We had adjusted EBITDAX of $202 million, up 108% over Q1 2019. We also reported operating cash flow of $156 million, up 120% over Q1 2019, or $0.55 per share, and adjusted net income for the quarter of $24 million or $0.12 per share. Now I'll have Roland cover the financial results in more detail. Roland?

The strong natural gas production growth this quarter was offset by week natural gas prices in the first quarter.

For the quarter, we reported oil and gas sales of $271 million, which is a 105 increase over first quarter 19, we had adjusted EBITDAX.

Of $202 million up 108% over first quarter 2019, we also reported operating cash flow of $156 million up 120% over first quarter 19, or 55 cents per share.

And adjusted net income for the quarter of $24 million or 12 cents per share now have rolling cover the financial results for more detail role.

Roland O. Burns: Thanks, Jay. On slide four, we show the combined Comstock and Covey Park production from the Haynesville-Bossier Shale since 2016. In the first quarter of this year, production from our Haynesville-Bossier wells is up 27% to almost 1.3 billion cubic feet per day as compared to about 1 billion cubic feet per day Comstock and Covey Park combined produced in the first quarter of 2019. Production grew only slightly from Q4 of last year due to the fact that our first quarter completions came online fairly late in the quarter, and we had a higher than normal shut-in rate this quarter, as we'll go over in a minute. We did put 11.5 net wells on production during the quarter.

Roland Burns: Thanks, Jay. On slide four, we show the combined Comstock and Covey Park production from the Haynesville-Bossier Shale since 2016. In the first quarter of this year, production from our Haynesville-Bossier wells is up 27% to almost 1.3 billion cubic feet per day as compared to about 1 billion cubic feet per day Comstock and Covey Park combined produced in the first quarter of 2019. Production grew only slightly from Q4 of last year due to the fact that our first quarter completions came online fairly late in the quarter, and we had a higher than normal shut-in rate this quarter, as we'll go over in a minute. We did put 11.5 net wells on production during the quarter.

Thanks, Jay on slide four we show the combined comp stocking heavy part production from the Haynesville Bowsher shale since 2016.

In the first quarter up.

This year production from our Haynesville Bowsher wealth is up 27% to almost 1.3 billion cubic feet per day as compared to the about 1 billion cubic feet per day Comstock is heavy part combined produced in the first quarter of 2019.

Production grew only slightly from the fourth quarter of last year.

It is due to the fact that our first quarter completions came by line fairly late in the quarter and we had a higher than normal shut in rate this quarter as well go over in a minute.

We did put 11.5 net wells on production during the quarter.

Roland O. Burns: In Q2, we see the rate of our Haynesville-Bossier properties, you know, really staying relatively flat with only about 4.5 net wells coming on production during Q2. Our completion activity is expected to pick back up in Q3, and we'll see some growth in Q3 and Q4 of this year. Slide 5 recaps the production we had shut in for the quarter, and production was shut in principally for offset frac activity, either by us or by offset operators. Our Q1 shut-in volumes increased to 5% as compared to only 2% in Q4 of last year. Offset operator activity as well as our own completion activity caused us to shut in production in some of our best producing areas.

Roland Burns: In Q2, we see the rate of our Haynesville-Bossier properties, you know, really staying relatively flat with only about 4.5 net wells coming on production during Q2. Our completion activity is expected to pick back up in Q3, and we'll see some growth in Q3 and Q4 of this year. Slide 5 recaps the production we had shut in for the quarter, and production was shut in principally for offset frac activity, either by us or by offset operators. Our Q1 shut-in volumes increased to 5% as compared to only 2% in Q4 of last year. Offset operator activity as well as our own completion activity caused us to shut in production in some of our best producing areas.

And the second quarter, we see that rate of our haynesville pose your properties.

Really staying relatively flat.

But with only about 4.5 net wells coming on production during the second quarter.

Our completion activity is expected to pick back up in the third quarter.

We'll see some growth in the third quarter and fourth quarter. This year.

Slide five recaps the production we had shut in for the quarter and this was.

Actually we shut in principally for offset Frac activity.

Either by us or by offset operators.

Our first quarter shut in volumes increased to 5% as compared to only 2% in the fourth quarter last year.

Offset operate activity as well as our own completion activity process to shut in production in some of our best producing areas.

Roland O. Burns: Given the lower number of completions planned during the second quarter and our planned activity level going forward this year, we do expect the shut in volumes to return to the 2% to 3% level over the rest of the year. On slide six, we summarize our financial results for Q1 2020. Our production for the first quarter totaled 126 Bcfe, including 454,000 barrels of oil. This is 230% higher than production in Q1 2019. Our oil and gas sales, including our realized hedging gains, were $271 million, 105% higher than the same quarter in 2019.

Roland Burns: Given the lower number of completions planned during the second quarter and our planned activity level going forward this year, we do expect the shut in volumes to return to the 2% to 3% level over the rest of the year. On slide six, we summarize our financial results for Q1 2020. Our production for the first quarter totaled 126 Bcfe, including 454,000 barrels of oil. This is 230% higher than production in Q1 2019. Our oil and gas sales, including our realized hedging gains, were $271 million, 105% higher than the same quarter in 2019.

Given that lowered ever completions plan during the second quarter and our planned activity level going forward. This year, we do expect to shut in volumes to return to the 2% to 3% level over the over the rest of the year.

On slide six we summarize our financial results for the first quarter of 2020.

Production for the first quarter totaled 126, Bcf, including 454000 barrels of oil.

This is 230% higher than production in the first quarter of 29 team.

Or oil and gas sales, including.

Our realized hedging gains were $271 million, 105% higher than the same quarter and 29 team.

Roland O. Burns: Oil prices in Q1 averaged $46.31, and our realized gas price, including our hedging gains, averaged $2.04 per Mcfe. Our natural gas price realization was down 29% in Q1, which offsets some of the substantial production growth we had. Adjusted EBITDAX came in at $202 million. That's a 108% increase over 2019. Operating cash flow was $156 million, a 120% increase over 2019. For the quarter, we reported net income of $30 million or $0.15 per fully diluted share. Adjusted net income, which would exclude unusual items, the largest being the unrealized gain on our derivatives, was $23.6 million or $0.12 per diluted share.

Roland Burns: Oil prices in Q1 averaged $46.31, and our realized gas price, including our hedging gains, averaged $2.04 per Mcfe. Our natural gas price realization was down 29% in Q1, which offsets some of the substantial production growth we had. Adjusted EBITDAX came in at $202 million. That's a 108% increase over 2019. Operating cash flow was $156 million, a 120% increase over 2019. For the quarter, we reported net income of $30 million or $0.15 per fully diluted share. Adjusted net income, which would exclude unusual items, the largest being the unrealized gain on our derivatives, was $23.6 million or $0.12 per diluted share.

Prices.

In the first quarter averaged $46, a 31, hsas and our realized gas price, including our hedging gains averaged $2.04 per mcf fee.

Our natural gas price realization was down 29% in the first quarter, which offset some of the substantial production growth we had.

Adjusted EBITDAX came in at 202 million.

That's 108% increase over 2019 operating cash flow was 156 million, 120% increase over.

2019.

For the quarter, we reported net income of $30 million or 15 cents for per fully diluted share.

Adjusted net income, which really excluding unusual items and the largest being the unrealized gain at our.

Derivatives was 23.6 million or 12 cents per diluted share.

Slide seven summarizes our current hedges that we have in place for our oil and gas production.

Roland O. Burns: Slide 7 summarizes our current hedges that we have in place for our oil and gas production. For this year, we have 619 million cubic feet per day of our gas and 3,450 barrels of our oil hedged. Since we reported earnings last, we've added 35 million cubic feet per day of gas swaps, about 50 million per day of gas collars for the Q4 of this year. The weighted average floor protection price of our 2020 hedges is $2.64 per Mcf. With the recent improvement in future gas prices, we've been actively adding to our 2021 hedge position. Since we last reported, we've added almost 270 million per day of natural gas swaps and 150 million per day of natural gas collars for 2021.

Roland Burns: Slide 7 summarizes our current hedges that we have in place for our oil and gas production. For this year, we have 619 million cubic feet per day of our gas and 3,450 barrels of our oil hedged. Since we reported earnings last, we've added 35 million cubic feet per day of gas swaps, about 50 million per day of gas collars for the Q4 of this year. The weighted average floor protection price of our 2020 hedges is $2.64 per Mcf. With the recent improvement in future gas prices, we've been actively adding to our 2021 hedge position. Since we last reported, we've added almost 270 million per day of natural gas swaps and 150 million per day of natural gas collars for 2021.

For this year, we have 619 billion cubic feet per day of our gas and 3450 barrels of our oil hedged.

Since we reported earnings last.

We've added 35 million cubic feet per day of gas swaps about 50 million per day of gas collars for the fourth quarter. This year.

The weighted average floor protection price of our 2020 hedges is $2 at 64 cents per Mcf.

But the recent.

Improvement in future gas prices, we've been actively adding to our 2021 hedge position since we last reported.

We've added almost 270 million per day of natural gas swaps and 150 million per day of natural gas collars.

For 2021.

So now we have about 540 million of our 2021 gas production hedged and the average floor protection.

Roland O. Burns: Now we have about 540 million of our 2021 gas production hedged, and the average floor protection of our hedges is $2.52 per Mcf. We also recently added 30 million per day of swaps covering our 2022 production at a price of $2.53 per Mcf. I'll remind you, our policy is to continue to target hedging 50% to 60% of our expected production on a rolling twelve-month basis. On slide 8, we detail our operating cost per Mcfe, which kind of demonstrates our very low cost structure. Our operating cost per Mcfe fell to $0.50 in Q1 as compared to the Q4 rate of $0.55. It's substantially lower than Q1 2019, where our operating costs were $0.74.

Roland Burns: Now we have about 540 million of our 2021 gas production hedged, and the average floor protection of our hedges is $2.52 per Mcf. We also recently added 30 million per day of swaps covering our 2022 production at a price of $2.53 per Mcf. I'll remind you, our policy is to continue to target hedging 50% to 60% of our expected production on a rolling twelve-month basis. On slide 8, we detail our operating cost per Mcfe, which kind of demonstrates our very low cost structure. Our operating cost per Mcfe fell to $0.50 in Q1 as compared to the Q4 rate of $0.55. It's substantially lower than Q1 2019, where our operating costs were $0.74.

Of our hedges is $2 at 52 cents per Mcf.

We also recently added 30 million per day of swaps covering our 20.

22 production at a price of $2.53 per Mcf.

At our about your our policy is to continue to target hedging, 50% to 60% of our expected production on a rolling 12 month basis.

On slide eight we detail.

Our operating cost per Mcf fee.

Which kind of demonstrates our very low cost structure, our operating cost per Mcf. He fell to 50 cents in the first quarter as compared to the fourth quarter rate of 55 cents.

And it substantially lower than the first quarter of 2019 were operating costs were 74 cents.

Our gathering costs were 23 cents production taxes average for says and just the field level.

Roland O. Burns: Our gathering costs were $0.23, production taxes averaged $0.04, and just the field level operating costs were $0.23 for the quarter. On slide 9, we detail our corporate overhead per Mcfe. Our cash G&A costs per Mcfe were $0.06 in Q1 as compared to Q4 at $0.04. Usually, the first quarter has the highest amount of just overall corporate G&A due to the extra professional costs that we usually incur in connection with our year-end close. On slide 10, we detailed our depreciation, depletion, and amortization per Mcfe produced. Our DD&A averaged $0.88 in Q1, very comparable to the $0.89 we had in Q4. It's a nice improvement over the 99-cent rate we had in Q1 2019.

Roland Burns: Our gathering costs were $0.23, production taxes averaged $0.04, and just the field level operating costs were $0.23 for the quarter. On slide 9, we detail our corporate overhead per Mcfe. Our cash G&A costs per Mcfe were $0.06 in Q1 as compared to Q4 at $0.04. Usually, the first quarter has the highest amount of just overall corporate G&A due to the extra professional costs that we usually incur in connection with our year-end close. On slide 10, we detailed our depreciation, depletion, and amortization per Mcfe produced. Our DD&A averaged $0.88 in Q1, very comparable to the $0.89 we had in Q4. It's a nice improvement over the 99-cent rate we had in Q1 2019.

Operating costs were 23 cents for the quarter.

On slide that we detail our corporate overhead per Mcf fee, our cash DNA cost per Mcf, we're success in the first quarter as compared to the fourth quarter at four cents.

And usually the first quarter has.

The highest them out of just overall corporate gionee due to the extra professional costs that we easily incurred in connection with our year end close.

On slide 10, we detailed our depreciation depletion and amortization per Mcf produce.

So our DNA averaged 88 cents in the first quarter very comparable to the 89 cents, we had in the fourth quarter.

And.

Nice improvement over the 99 set rate we had in the first quarter of two.

2019.

On slide 11, we recap our first quarter spending not our drilling and development activity and then what we expect to spend for all of 2020.

Roland O. Burns: On slide 11, we recap our Q1 spending on our drilling and development activity and then what we expect to spend for all of 2020. In the first quarter, we spent $130 million on development activities. $104 million was related to our Haynesville Shale operated operations. We drilled 13 or 19.6 net operated horizontal Haynesville wells in the quarter, and we completed 13 or 9.3 net wells that were drilled in 2019. We spent another $26 million on non-operated or other activity in the quarter. We did generate operating cash flow of $156 million in the quarter, resulting in free cash flow of $16 million in the quarter after we paid the $9.6 million dividend on our preferred shares.

Roland Burns: On slide 11, we recap our Q1 spending on our drilling and development activity and then what we expect to spend for all of 2020. In the first quarter, we spent $130 million on development activities. $104 million was related to our Haynesville Shale operated operations. We drilled 13 or 19.6 net operated horizontal Haynesville wells in the quarter, and we completed 13 or 9.3 net wells that were drilled in 2019. We spent another $26 million on non-operated or other activity in the quarter. We did generate operating cash flow of $156 million in the quarter, resulting in free cash flow of $16 million in the quarter after we paid the $9.6 million dividend on our preferred shares.

So.

In the first quarter, we spent $130 million on development activities 104 million was related to our Haynesville shale operate in.

Operations.

We drilled 13 or 19.6 net operated horizontal haynesville wells in the quarter and we completed.

13, or 9.3 net wells.

That were drilled and in 2019.

We spent another $26 million on non operator other activity in the quarter.

We did generate operating cash flow of 156 day and in the quarter, resulting in free cash flow of $16 billion in the quarter. After we paid to $9.6 million dividend on our preferred shares.

Roland O. Burns: We dropped our activity level to 6 operated rigs in January and then further reduced our rig count to 5 operated rigs in March. Last month, we dropped another rig to reduce our current operated rigs down to 4 rigs, although we do anticipate picking a rig back up later this year. We continue to be very responsive to the changing natural gas prices and remain very focused on generating free cash flow in 2020. We expect to spend, in total, $412 million in 2020 to drill 47 or 36.5 net operated Haynesville wells. We expect to be in various stages of drilling of an additional 18 or 12.5 net wells at the end of this year.

Roland Burns: We dropped our activity level to 6 operated rigs in January and then further reduced our rig count to 5 operated rigs in March. Last month, we dropped another rig to reduce our current operated rigs down to 4 rigs, although we do anticipate picking a rig back up later this year. We continue to be very responsive to the changing natural gas prices and remain very focused on generating free cash flow in 2020. We expect to spend, in total, $412 million in 2020 to drill 47 or 36.5 net operated Haynesville wells. We expect to be in various stages of drilling of an additional 18 or 12.5 net wells at the end of this year.

We dropped or activity level to six operated rigs at January and then further reduced our rig count to five operated rigs in March.

Last month, we we dropped another rig to reduce our current operated rigs down to four rigs that we do anticipate taking a rig backup later this year.

We continue to make very responsive to the changing natural gas prices and remained very focused on generating free cash flow in 2020.

We expect to stand.

Total $412 million in 2020 to drill 47 or 36.5 net operated Haynesville wells.

And then what we expect to be in various stages of drilling that an additional 18 or 12.5 net wells at the end of this year.

At this lower rig count.

Roland O. Burns: At this lower rig count, taking into account the current natural gas prices, we do still expect to generate significant free cash flow this year of approximately $150 to 200 million, despite the lower natural gas prices we've experienced so far this year. Slide 12 shows our balance sheet at the end of Q1 2020. We recently completed the spring redetermination with our 18-member bank group. With bank price decks down 24% for gas and then down almost 52% for oil for the spring redetermination season, our borrowing base was reduced down to $1.4 billion. We currently have $1.25 billion drawn on our revolving credit facility, but expect to continue to pay that down with the free cash flow that we're generating during the rest of this year.

Roland Burns: At this lower rig count, taking into account the current natural gas prices, we do still expect to generate significant free cash flow this year of approximately $150 to 200 million, despite the lower natural gas prices we've experienced so far this year. Slide 12 shows our balance sheet at the end of Q1 2020. We recently completed the spring redetermination with our 18-member bank group. With bank price decks down 24% for gas and then down almost 52% for oil for the spring redetermination season, our borrowing base was reduced down to $1.4 billion. We currently have $1.25 billion drawn on our revolving credit facility, but expect to continue to pay that down with the free cash flow that we're generating during the rest of this year.

Andy taken into account the current natural gas prices.

We do still expect is generating significant free cash flow this year of approximately $150 million to $200 million. Despite the lower natural gas prices, we've experienced so far this year.

Slide 12 shows our balance sheet that into the first quarter of 2020.

We recently completed the spring Redetermination with our 18 member Bank group.

With bike price decks down 24%.

For gas.

And then it down almost 52% for oil.

For the spring Redetermination season, our borrowing base was reduced down to $1.4 billion. We currently have one day in 250 million drawn on our.

Revolving credit facility, but expect to continue to pay that down with the free cash flow that we're generating during the rest of this year.

With the quarter ending cash position of $16 million, our current liquidity stands at $166 million.

Roland O. Burns: With the quarter-ending cash position of $16 million, our current liquidity stands at $166 million. We also have $1.475 billion of our senior notes outstanding, including the $625 million of our 7.5% senior notes, which are due in 2025, and $850 million of our 9.75% senior notes due in 2026. With no debt maturities until 2024.

Roland Burns: With the quarter-ending cash position of $16 million, our current liquidity stands at $166 million. We also have $1.475 billion of our senior notes outstanding, including the $625 million of our 7.5% senior notes, which are due in 2025, and $850 million of our 9.75% senior notes due in 2026. With no debt maturities until 2024.

We also have.

One day, and 475 million of our senior notes outstanding, including the 625 million of our 7.5% senior notes, which are due in 2025, an 850 million for nine in three quarters senior notes due in 2026.

With no debt maturities until 2024, and our current leverage ratio comfortably below our leverage ratio covenant of four times, we're very well positioned to whether the current low oil and gas price environment.

M. Jay Allison: Our current leverage ratio comfortably below our leverage ratio covenant of four times. We are very well-positioned to weather the current low oil and gas price environment. As a side note, I want to point out that our Universal Shelf Registration Statement that we filed three years ago expires next week. We plan to file a replacement shelf tomorrow, as we always wanna have that available to us. Now I'll turn it over to Dan to cover the Q1 drilling results in more detail.

Jay Allison: Our current leverage ratio comfortably below our leverage ratio covenant of four times. We are very well-positioned to weather the current low oil and gas price environment. As a side note, I want to point out that our Universal Shelf Registration Statement that we filed three years ago expires next week. We plan to file a replacement shelf tomorrow, as we always wanna have that available to us. Now I'll turn it over to Dan to cover the Q1 drilling results in more detail.

That's a side note I wanted to point out that our universal shelf registration statement that we filed three years ago expires next week.

So we plan to follow replacement shelf tomorrow, as we always want to have that available to us.

Now I'll turn it over to Dan to cover the first quarter drilling results in more detail.

Daniel S. Harrison: Thank you, Roland. If you look on slide 13, this will show the outline of the acreage position as it stands now. We currently stand at 307,000 net acres. We currently have 1,977 net locations identified on the acreage, and 95% of this acreage is currently held by production. This translates into minimal drilling commitments and allows us the maximum flexibility with our drilling schedule for any changes in future market conditions. We also control the majority of the acreage with a 91% operated position and an average working interest of 76%. We've now drilled and completed 237 wells in the play, with an average IP of 23 million cubic feet per day.

Daniel Harrison: Thank you, Roland. If you look on slide 13, this will show the outline of the acreage position as it stands now. We currently stand at 307,000 net acres. We currently have 1,977 net locations identified on the acreage, and 95% of this acreage is currently held by production. This translates into minimal drilling commitments and allows us the maximum flexibility with our drilling schedule for any changes in future market conditions. We also control the majority of the acreage with a 91% operated position and an average working interest of 76%. We've now drilled and completed 237 wells in the play, with an average IP of 23 million cubic feet per day.

Thank you Roland.

If you look on slide 13, this will show the outline of the acreage position as it stands now with current currently stand at 307000 net acres.

We currently have 1977 net locations identified on the acreage at 95% of this acreage is currently held by production.

This translates into minimal drilling commitments in that allows us the maximum flexibility with our drilling schedule for any changes in future market conditions.

We also control the majority of the acreage with the 91% operated position at an average working interest of 76%.

We've now done really completed 237 wells in the play.

With an average of fee of 23 million cubic feet per day.

If you look at slide 14. This shows a breakdown of our Haynesville those are drilling inventory at the end of the first quarter.

Daniel S. Harrison: If you look at slide 14, this shows a breakdown of our Haynesville-Bossier drilling inventory at the end of Q1. Our total gross operated inventory now stands at 2,383 locations. Our average net interest is 76%, equating to 1,803 net operated locations. On the non-operated side, we have an additional 1,451 gross non-operated locations with an average 12% net interest, which adds another 174 net locations. In our gross operated inventory mix, we currently have 580 short laterals, 937 medium laterals, and 866 long laterals. 60% of the gross operated locations are in the Haynesville, and the remaining 40% are in the Bossier.

Daniel Harrison: If you look at slide 14, this shows a breakdown of our Haynesville-Bossier drilling inventory at the end of Q1. Our total gross operated inventory now stands at 2,383 locations. Our average net interest is 76%, equating to 1,803 net operated locations. On the non-operated side, we have an additional 1,451 gross non-operated locations with an average 12% net interest, which adds another 174 net locations. In our gross operated inventory mix, we currently have 580 short laterals, 937 medium laterals, and 866 long laterals. 60% of the gross operated locations are in the Haynesville, and the remaining 40% are in the Bossier.

Total gross operated inventory now stands at 2383 locations.

Our average net interest is 76%.

Equating to 1803 net operated locations.

On the non operated side, we have an additional 1451 gross and non operated locations with an average 12% net interest which adds another hundred 74 net locations.

In our gross operated inventory mix. We currently have 580 short laterals 937 medium laterals and 866 long levels.

60% of the gross operated locations are in the Haynesville.

And the remaining 40% or in the mosher.

This inventory provides the tell me with well over 30 years of drilling locations based on our forecasted 2020 activity level.

Daniel S. Harrison: This inventory provides the company with well over 30 years of drilling locations based on our forecasted 2020 activity level. On slide 15 is a summary of the 20 new wells we've completed and turned to sales since the last call, and also shows an outline of where these latest wells are located across the acreage. As you can see, the majority of the new wells were completed in our Stateline and Elm Grove areas. The initial production rates ranged from 15 to 32 million cubic feet per day with an average IP of 24 million cubic feet per day. The wells were drilled with varying lengths from 4,574 feet up to 9,885 feet with an average lateral of 8,758 feet.

Daniel Harrison: This inventory provides the company with well over 30 years of drilling locations based on our forecasted 2020 activity level. On slide 15 is a summary of the 20 new wells we've completed and turned to sales since the last call, and also shows an outline of where these latest wells are located across the acreage. As you can see, the majority of the new wells were completed in our Stateline and Elm Grove areas. The initial production rates ranged from 15 to 32 million cubic feet per day with an average IP of 24 million cubic feet per day. The wells were drilled with varying lengths from 4,574 feet up to 9,885 feet with an average lateral of 8,758 feet.

On Slide 15 is a summary of the 20, new wells, we completed in terms of sales since the last call.

And also sales and outline what are these latest wells are located across the acreage.

As you can see the majority of the new wells were completed in our state line and Elm Grove areas.

Initial production rates ranged from 15 to 32 million cubic feet per day with an average out the of 24 billion cubic feet per day.

The wells were drilled a version links from 4574 feet up to 9885 feet with an average.

Lateral 8758 feet.

The wells were completed with sand loading sand loadings, ranging from 2200 pounds per foot to 3500 pounds per foot.

Daniel S. Harrison: The wells were completed with sand loadings ranging from 2,200 lbs/ft up to 3,500 lbs/ft, with the majority of the wells completed with 2,800 lbs/ft. Currently, we do not have any ongoing completion activity or frac crews working. We will be bringing back multiple crews at the beginning of Q3 to resume our completion activity. Our current DUC count stands at 13 wells, and we anticipate having a total of 20 DUCs at the beginning of Q3 when our completion activity resumes. On slide 16, this provides a snapshot of our all-in D&C cost and trend since early 2017. These results track our wells which have lateral lengths of greater than 6,000 ft.

Daniel Harrison: The wells were completed with sand loadings ranging from 2,200 lbs/ft up to 3,500 lbs/ft, with the majority of the wells completed with 2,800 lbs/ft. Currently, we do not have any ongoing completion activity or frac crews working. We will be bringing back multiple crews at the beginning of Q3 to resume our completion activity. Our current DUC count stands at 13 wells, and we anticipate having a total of 20 DUCs at the beginning of Q3 when our completion activity resumes. On slide 16, this provides a snapshot of our all-in D&C cost and trend since early 2017. These results track our wells which have lateral lengths of greater than 6,000 ft.

With the majority of the wells completed with 2800 pounds per foot.

Currently we do not have any ongoing completion activity or frac crews working.

We will be bringing back multiple crews at the beginning of the third quarter to resume our completion activity.

Our current DUC count stands at 13 wells and we anticipate having a total of 20 ducs at the at the beginning to the third quarter when our completion activity presents.

On Slide 16. This provides a snapshot of our all in DNC cost and shrink on since early 2017.

These results track, our wells, which have lateral links greater than 6000 feet. The DMC costs have been steadily trending down since early 2018 any was the first quarter being the lowest quarterly DNC calls we have achieved to date in the Blake.

Daniel S. Harrison: The D&C costs have been steadily trending down since early 2018, ending with Q1 being the lowest quarterly D&C cost we have achieved to date in the play. Our D&C cost in Q1 averaged $1,121 a foot. This is a reduction of $199 a foot or 15% from our Q1 2019 cost of $1,320 a foot. Our completion cost, or more specifically, our frac cost, continues to be the main driver here. During Q1, we began testing a smaller modified frac design on several infill and co-developed locations that we believe will yield better returns in economics while also preserving capital.

Daniel Harrison: The D&C costs have been steadily trending down since early 2018, ending with Q1 being the lowest quarterly D&C cost we have achieved to date in the play. Our D&C cost in Q1 averaged $1,121 a foot. This is a reduction of $199 a foot or 15% from our Q1 2019 cost of $1,320 a foot. Our completion cost, or more specifically, our frac cost, continues to be the main driver here. During Q1, we began testing a smaller modified frac design on several infill and co-developed locations that we believe will yield better returns in economics while also preserving capital.

Our DMC cost in the first quarter averaged $1121 a foot.

This is a reduction of $199 a sort of 15% from our first quarter of 2019 calls.

$1320.

Our completion cost or more specifically, our freckles continues to be the main driver here.

During the first quarter, we began testing a smaller modified frac design will several infield and cold develop locations.

That we believe will yield better returns and economics, while still preserving capital.

Daniel S. Harrison: We plan to continue testing this modified design when our completion activity resumes in Q3, and we will continue to monitor the performance from these wells. Our goal is to reduce our D&C costs even further down to $1,000 a foot. We firmly believe we can achieve this goal, and we have actually made good progress toward that end with the wells that we have already completed to date in Q2. Our goal is simple, and that is to deliver the highest return and create the most value we can on the capital deployed. That summarizes up the operations. I'll now turn it back over to Jay for some final comments.

Daniel Harrison: We plan to continue testing this modified design when our completion activity resumes in Q3, and we will continue to monitor the performance from these wells. Our goal is to reduce our D&C costs even further down to $1,000 a foot. We firmly believe we can achieve this goal, and we have actually made good progress toward that end with the wells that we have already completed to date in Q2. Our goal is simple, and that is to deliver the highest return and create the most value we can on the capital deployed. That summarizes up the operations. I'll now turn it back over to Jay for some final comments.

We plan to continue testing this modified design win our completion activity resumes third quarter.

And we will continue to monitor the performance from these wells.

Our goal was to reduce our DNC costs, even further down to $1000 is good we firmly believe we can achieve this goal.

We've actually made good progress toward that end with the wells that we have already completed to date in the second quarter.

Our goal is sample and that is to deliver the highest return rate. The most value we can only capital deployed.

At Sunrise is up the operations I'll now turn it back over to Jay for some final comments.

M. Jay Allison: All right. Again, thank you for the report. I would direct everybody to slide 17, where we summarize our outlook for the year. You know, this year we are primarily focused on free cash flow generation and managing the company through the current low oil and natural gas price environment. While current natural gas prices remain relatively low, the outlook for natural gas has improved substantially for late 2020 and 2021, driven by our expectation for significant declines in natural gas supply in 2020 and 2021 due to a continued reduction in natural gas-directed drilling and completion activity, and less associated gas production from related activities in oil basins resulting from the collapse of oil prices. Our Haynesville drilling program generates economic returns even at today's low natural gas prices, which Roland and Dan have just showed you.

Jay Allison: All right. Again, thank you for the report. I would direct everybody to slide 17, where we summarize our outlook for the year. You know, this year we are primarily focused on free cash flow generation and managing the company through the current low oil and natural gas price environment. While current natural gas prices remain relatively low, the outlook for natural gas has improved substantially for late 2020 and 2021, driven by our expectation for significant declines in natural gas supply in 2020 and 2021 due to a continued reduction in natural gas-directed drilling and completion activity, and less associated gas production from related activities in oil basins resulting from the collapse of oil prices. Our Haynesville drilling program generates economic returns even at today's low natural gas prices, which Roland and Dan have just showed you.

Alright again.

Thank you for the report I would direct to everybody to slide 17 will we summarize our outlook for the year.

And this year, we are primarily focused on free cash flow generation and managing the company through the current low oil and natural gas price environment.

Current natural gas prices remained relatively low.

The outlook for natural gas has improved substantially for late 2020 to 2021, driven by our expectation for significant declines in natural gas supply in 2020 2021 do like due to continued reduction in natural gas directed drilling and completion activity and less associated gas production.

From related activities in oil basins, resulting from the collapse of oil prices.

Our Haynesville drilling program generates economic returns even at today's low natural gas prices patrol and Dan and just showed you.

M. Jay Allison: We have cut back the number of wells we're drilling in order to generate free cash flow that we will use to pay down our debt and strengthen our balance sheet. That's a primary focus. The strength we have is our industry-leading cost structure and industry-leading well economics. We still expect 6% to 8% pro forma production growth in 2020, even with the reduced activity. We have prioritized free cash flow goals in 2020 over production growth, but have maintained adequate investment to keep our production flat on a longer term basis. We've hedged almost half of our production for the next twelve months and have adequate liquidity of $166 million. I'll now have Ronald Mills, our VP of Finance, provide some specific guidance for the rest of the year. Ron?

Jay Allison: We have cut back the number of wells we're drilling in order to generate free cash flow that we will use to pay down our debt and strengthen our balance sheet. That's a primary focus. The strength we have is our industry-leading cost structure and industry-leading well economics. We still expect 6% to 8% pro forma production growth in 2020, even with the reduced activity. We have prioritized free cash flow goals in 2020 over production growth, but have maintained adequate investment to keep our production flat on a longer term basis. We've hedged almost half of our production for the next twelve months and have adequate liquidity of $166 million. I'll now have Ronald Mills, our VP of Finance, provide some specific guidance for the rest of the year. Ron?

We have cut back the number wells, we're drilling in order to generate free cash flow that we were used to pay down our debt and strengthen our balance sheet Thats a primary focus the strength, we have is our industry, leading cost structure and industry, leading well economics.

We still expect six 8% pro forma production growth in 2020, even with the reduced activity.

Prioritize free cash flow goals in 2020 over production growth, but have maintained the adequate investment to keep production flat on a longer term basis.

It depends almost half of our production for the next 12 months and have adequate liquidity of $166 million I will now have Ron Mills, our VP of finance provides some specific guidance for the rest of the year Ron.

Ronald Mills: Thank you, Jay. On slide 18, we provide financial guidance for the rest of the year for analysts and investors who model the company. I point out the guidance is unchanged from what we provided when we reported the Q4 earnings in late February. Our total production guidance is expected to average 1.25 to 1.45 Bcfe per day, of which 97% to 99% is expected to be natural gas. In that number, we have now factored in a 40% shut-in factor for our oil production over the remainder of the year due to potential shut-ins, though I would point out that the impact to date has not been that high. We just wanted to make sure we prepared for potential shut-ins as oil producers are announcing significant shut-ins.

Thank you James on Slide 18, we provide financial guidance for their as the year for analyst and investors you model the company.

I point out the guidance is unchanged from what we provided when we reported fourth quarter earnings in late February.

Total production guidance is expected to averaged 1.25 to 1.4 or five Bcf per day, which 97% to 99% is expected to be natural gas.

In that number we have now factored in a 40% shut in factor for our oil production over the remainder of the year due to potential shut ins, though I would point out that the impact to date has not been.

That high we just wanted to make sure. We we prepared for potential shut ins as oil producers are are announcing significant shut ins on the cost side. Our lease operating costs are expected to average 23 to 27 cents per mcf fee in 2020.

Ronald Mills: On the cost side, our lease operating costs are expected to average $0.23 to $0.27 per Mcfe in 2020. Our gathering and transportation costs are also expected to average $0.23 to $0.27 per Mcfe in 2020. Production taxes are expected to remain in the 6 to 8 cents per Mcfe range, and DD&A is expected to remain in the $0.85 to $0.95 per Mcfe range. Cash G&A for the year is expected to average 5 to 7 cents per Mcfe. For the rest of the call, we'll take questions from the analysts who follow the company.

Our gathering and transportation costs are also expected to average 23 to 27 cents per Mcf eight in 2020.

Production taxes.

I'd like to do remain in the six to eight cents per Mcf be range and DDNA is expected to remain.

In the 85 to 95 cents per Mcf the range.

Cash DNA for the year is expected to average five to seven cents per Mcf fee.

For the rest the call we'll take questions from the analysts who follow the company.

As a reminder to ask a question.

Operator: As a reminder, to ask a question, simply press star then the telephone keypad. Our first question comes from Dun McIntosh with Johnson Rice. Please go ahead.

And our first question comes from Dan Mackintosh with Johnson Rice. Please go ahead.

Good morning, Jay enroll in Enron and congrats on another strong quarter, nice nice EBITDA beat versus and consensus.

Dun McIntosh: Morning, Jay and Roland and Ron, and congrats on another strong quarter. Nice EBITDA beat versus consensus. My question is on activity kind of over the remainder of the year, yeah. Q1, you're at 13 completions and you're pointing to 35 for the year. Could you talk about the cadence over the remainder? I'd imagine that, you know, maybe it's more back half-weighted as you look to bring on volumes into what y'all clearly think is gonna be a stronger tape at the end of the year and heading into 2021.

[music].

My question is on a activity kind of the remainder of the year you one Q you're at 13 completions in your kind of as you pointed to 35 for the year can you talk about a cadence over the remainder I'd imagine that maybe it's more back half weighted as you look to bring on volumes into well clearly think is going to be a stronger take a deep into the year in heading into 2021.

Yes, Rolla will address that but I want you to know we've got total flexibility on that too okay.

M. Jay Allison: Yeah, Roland will address that, but I want you to know we've got total flexibility on that too, okay? With our decisions will be, you know, will be determined by where the commodity prices are, where the sector is. Roland.

Jay Allison: Yeah, Roland will address that, but I want you to know we've got total flexibility on that too, okay? With our decisions will be, you know, will be determined by where the commodity prices are, where the sector is. Roland.

With our decisions will be a bit of term Bob were the commodity processes are where the sector as CIO role.

Roland O. Burns: Sure. I think, you know, like we pointed out earlier, Q2, you know, we only look to be bringing about 4.4 net wells to sales, and those are already, you know, on, you know, pretty much done now. So they mostly happened in April. As Dan pointed out, we're not, you know, we're giving the frac crews a little break here. But we do expect to return to completing wells in Q3. Q3 and Q4, you know, we expect to see the rest of that, those wells completed in those two quarters that we had planned for the year. Yeah, but we do have the ability to decide to delay that if we want to in Q3.

Roland Burns: Sure. I think, you know, like we pointed out earlier, Q2, you know, we only look to be bringing about 4.4 net wells to sales, and those are already, you know, on, you know, pretty much done now. So they mostly happened in April. As Dan pointed out, we're not, you know, we're giving the frac crews a little break here. But we do expect to return to completing wells in Q3. Q3 and Q4, you know, we expect to see the rest of that, those wells completed in those two quarters that we had planned for the year. Yeah, but we do have the ability to decide to delay that if we want to in Q3.

Sure. It I think like we pointed out earlier, the second quarter you know.

We're early we are they look to be can bring about 4.4 net wells to sales and those are already are on.

Pretty much done now so is it mostly happened in April as Dan pointed out we're not we're given the frac crews are little break here.

And so will that but we do expect to return to completing wells in the third quarter answer the third and fourth quarter, we expect to see.

The rest of that.

Does the wells completed in those two quarters that we had planned for the year, yes, but we do have the ability to decide to delay that if we want to in the third quarter. So we're kind of look at sea without what's going on and this plan has really put together you know really back.

Roland O. Burns: We'll kind of look at what's going on. This plan was really put together, you know, really back when we reported the Q4 because we knew the summer was gonna be a weaker part of gas prices. We wanted to have the free cash flow for the year kind of generated earlier in the year, not toward the end of the year, and have, you know, more production come in, you know, online, you know, toward the end of the year, going into the better market that we're seeing, you know, for the very end of 2020 and 2021.

Roland Burns: We'll kind of look at what's going on. This plan was really put together, you know, really back when we reported the Q4 because we knew the summer was gonna be a weaker part of gas prices. We wanted to have the free cash flow for the year kind of generated earlier in the year, not toward the end of the year, and have, you know, more production come in, you know, online, you know, toward the end of the year, going into the better market that we're seeing, you know, for the very end of 2020 and 2021.

When we reported the fourth quarter, because we knew the summer what's going to be a weaker the weaker part of gas prices and we wanted to have the.

The free cash flow for the year kind of generated earlier in the year not towards the end of the year and I have.

More production come in on line here towards the end of the year going into the better market that we're seeing effort for the very end up 20 and 2021, so we havent.

Roland O. Burns: We haven't made any major adjustments to the program because we were already, you know, geared up for low prices, and actually prices are a little stronger than when we set the budgets, unlike a lot of the other operators on the well side that are catching up with the, you know, massive changes to the budget. Our plan was really, you know, almost designed perfectly for the environment, and everything is going very smoothly, you know, as anticipated.

Roland Burns: We haven't made any major adjustments to the program because we were already, you know, geared up for low prices, and actually prices are a little stronger than when we set the budgets, unlike a lot of the other operators on the well side that are catching up with the, you know, massive changes to the budget. Our plan was really, you know, almost designed perfectly for the environment, and everything is going very smoothly, you know, as anticipated.

Made any major adjustments to the program because we are already yeah. We already were geared up for low prices and actually prices are a little stronger than when we set the budgets.

I'd like you allow the other operators and the oil side that or are catching up with the massive changes to the budget. So we are plan was really almost design perfectly for the environment and everything is going very smoothly.

As anticipated hopefully you can see we've demonstrated in the past dividend to fourth quarter of 19, we announced that we have nine rigs we want to start the year January 120 was six rigs. So we're very proactive moved in the fourth quarter to protect this free cash flow I'm, a little did we noted become more and more.

M. Jay Allison: You know, hopefully you can see we've demonstrated in the past, even in Q4 2019, you know, we announced that we have 9 rigs. We wanna start the year 1 January 2020 with 6 rigs. We're very proactive even in Q4 to protect this free cash flow. I mean, little did we know it'd become more and more and more important. That's why we go from 6 rigs to 5. Then, as Roland mentioned a little earlier, we're at 4 rigs. We can toggle that back if we need to. That's where this 95% of our acreage is HBP, and we operate 91% of it. All those are big components that allow us to guide us through this environment.

Jay Allison: You know, hopefully you can see we've demonstrated in the past, even in Q4 2019, you know, we announced that we have 9 rigs. We wanna start the year 1 January 2020 with 6 rigs. We're very proactive even in Q4 to protect this free cash flow. I mean, little did we know it'd become more and more and more important. That's why we go from 6 rigs to 5. Then, as Roland mentioned a little earlier, we're at 4 rigs. We can toggle that back if we need to. That's where this 95% of our acreage is HBP, and we operate 91% of it. All those are big components that allow us to guide us through this environment.

More important thus, while we go from six rigs to five and then as Rolla Mitch will earlier were four rigs. So we can toggle that back if we need to that's where this 90% of our acreage is HBP to we operate 91% of all those are big components that allow us to got us to this environment. So our goal again is to create value.

M. Jay Allison: Our goal, again, is to create value by adjusting this budget if we need to, and hopefully you've seen us demonstrate that in the past.

Jay Allison: Our goal, again, is to create value by adjusting this budget if we need to, and hopefully you've seen us demonstrate that in the past.

By adjusting this budget, if we need to and hopefully you've seen us demonstrate that in the past.

Yes, absolutely and I'm, sorry, if I, if I Miss that earlier in the call I got disconnected for a while there.

Dun McIntosh: Yeah, absolutely. I'm sorry if I missed that earlier in the call. I got disconnected for a while there.

M. Jay Allison: Well, yeah, thank you for joining. Again, it's a crowded day.

Jay Allison: Well, yeah, thank you for joining. Again, it's a crowded day.

Yes, thank you for joining and again, it's a crowded day.

Dun McIntosh: Yeah. For my second question, on the borrowing base, you know, obviously, any reduction is not what you're looking for. All things considered, when you look at what's happened kind of across the space to some of your peers, you know, you're still left with $150 million in liquidity at the end of the quarter. In my model, I mean, I've got you generating about $150 million over the remainder of the year. First, I assume that all that free cash goes straight to the revolver and reducing that. Second, how are you thinking about, you know, ways to maybe further reduce that beyond the free cash flow?

And then my for my second question.

On the borrowing base you know obviously.

Any reduction is not now what you're looking for but all things considered when you look at what's happened kind of across space to some of your some of your peers.

You've still got what you're still left with a 150 million in liquidity at the ended the quarter and then in my model I mean, I've got to generating about 150 over the remainder of the year. So first I assume that that all that free cash goes straight to the revolver introduced in that and then second how are you thinking about ways to maybe further reduce that.

Beyond the free cash flow or is that just kind of the strategy at this point, just as harvest Occassion and keep just chipping away at it.

Dun McIntosh: Is that just kind of the strategy at this point, just to harvest the cash and keep just chipping away at it?

Yes, I think that as you pointed to in as we pointed out yes. There is a very significant decline in prices, even though we had nice growth in our as you saw from the year end report nice growth in our proved developed producing reserves.

Roland O. Burns: Yeah, I think that as you pointed, you know, as we pointed out, yeah, there was a very significant decline in prices, even though we had nice growth in our, as you saw from the year-end report, nice growth in our proved developed producing reserves. But, you know, such a large reduction in prices, you know, which were, you know, below the, you know, the bank price decks, which are well below the strip prices, during the spring redetermination. But I do think we've seen the worst of that. I mean, I think we've already seen two of our major banks start to raise their gas price decks and then lower their oil price decks further. I think there's a bigger separation going forward.

Roland Burns: Yeah, I think that as you pointed, you know, as we pointed out, yeah, there was a very significant decline in prices, even though we had nice growth in our, as you saw from the year-end report, nice growth in our proved developed producing reserves. But, you know, such a large reduction in prices, you know, which were, you know, below the, you know, the bank price decks, which are well below the strip prices, during the spring redetermination. But I do think we've seen the worst of that. I mean, I think we've already seen two of our major banks start to raise their gas price decks and then lower their oil price decks further. I think there's a bigger separation going forward.

But you know such a large reduction in prices, which were below that the by price decks are well below the strip prices.

During for the spring Redetermination and.

So, but I do think we've seen the low the works to that I mean, I think we've already seen two of our major banks start to raise their gas price decks, and then lower their gold price decks. Further so I think theres a bigger separation going forward. So even a small increase in the gas price.

Roland O. Burns: Even a small increase in the gas price decks they use can add a significant amount, you know, to a borrowing base that maybe we'll see in the fall. We do think that the borrowing base, you know, has a lot of potential for growth as gas prices start getting closer to what the market's already showing for gas in 2021. We are gonna use the free cash flow to restore the liquidity that we had before the reduction to the borrowing base. That's always the plan. We think that will put us in good shape. You know, obviously, we'll

Roland Burns: Even a small increase in the gas price decks they use can add a significant amount, you know, to a borrowing base that maybe we'll see in the fall. We do think that the borrowing base, you know, has a lot of potential for growth as gas prices start getting closer to what the market's already showing for gas in 2021. We are gonna use the free cash flow to restore the liquidity that we had before the reduction to the borrowing base. That's always the plan. We think that will put us in good shape. You know, obviously, we'll

Next they use can begin to have a significant add a significant about to a borrowing base that maybe we'll see in the fall. So we do think that borrowing base.

Has a lot of potential for for growth as gas prices, they start getting closer to what the markets already showing for gas in 2021.

But yes, we are going to use that free cash flow to too.

Restore that liquidity that we had before the.

Reduction to the borrowing base, that's always the plan and.

And we think.

We think that will be oh.

Well put us in gets good good shape and then you know.

Obviously will.

Roland O. Burns: At some point, you know, we have an overall goal of getting leverage below 2, you know, and we're just a little bit slightly above 3 times levered now. I mean, our goal will be overall to continue to focus on the balance sheet and focus toward getting toward that goal. You know, stronger gas prices will help a lot next year. You know, I think we've got a good plan, and we'll continue to kind of execute on that.

Roland Burns: At some point, you know, we have an overall goal of getting leverage below 2, you know, and we're just a little bit slightly above 3 times levered now. I mean, our goal will be overall to continue to focus on the balance sheet and focus toward getting toward that goal. You know, stronger gas prices will help a lot next year. You know, I think we've got a good plan, and we'll continue to kind of execute on that.

At some point you know our goal is to yeah. We have an overall goal of getting leverage below two.

But we're just little bit or little slightly above three times levered now so our goal will be overall to continue to to focus on the balance sheet and focused or getting toward that goal and.

Stronger gas prices will help a lot next year and then.

And so I think that I think we've got a good plan and we'll continue to kind of execute on that one thing that came out in our borrowing base review was that the gold standard is that you really have through free cash flow. While you have a little growth and we do have that 150 to 200 million a true gold standard free cash flow.

M. Jay Allison: You know, the one thing that came out in our borrowing base review was that the gold standard is that you really have true free cash flow while you have a little growth. We do have that $150 to 200 million of true gold standard free cash flow while growing, you know, our production maybe at 6% to 8%. Some have free cash flow, but they have no growth, or they have negative growth. That was, I think, tested. I think the second thing I would answer, you know, 73% of this company is owned by the Jones family, and they have never been more excited about the growth and the opportunities. I think that's always something important that the shareholders need to know, that they have not lost their enthusiasm at all.

Jay Allison: You know, the one thing that came out in our borrowing base review was that the gold standard is that you really have true free cash flow while you have a little growth. We do have that $150 to 200 million of true gold standard free cash flow while growing, you know, our production maybe at 6% to 8%. Some have free cash flow, but they have no growth, or they have negative growth. That was, I think, tested. I think the second thing I would answer, you know, 73% of this company is owned by the Jones family, and they have never been more excited about the growth and the opportunities. I think that's always something important that the shareholders need to know, that they have not lost their enthusiasm at all.

While growing in all our production maybe that 6% to 8% so.

Some have free cash flow, but they have no growth really of negative growth and so that was I think tested in I think the second thing I would answer.

73% of this company is owned by the Jones family.

As I have never been more excited about the growth and the opportunities and I think that's always something important that that to shareholders need to know that they have not lost your enthusiasm at all in fact, there probably peak enthusiasm right now because they're very opportunistic.

M. Jay Allison: In fact, they're probably peak enthusiasm right now because they're very opportunistic. You know, I think we as a company, we're prepared for the cycle we're in. We've got the right assets, the right people, the right cost. The opportunity is there and, you know, we'll seize it. I think the banks trust us for that.

Jay Allison: In fact, they're probably peak enthusiasm right now because they're very opportunistic. You know, I think we as a company, we're prepared for the cycle we're in. We've got the right assets, the right people, the right cost. The opportunity is there and, you know, we'll seize it. I think the banks trust us for that.

And we think we as a company we're prepared for the Soc Orient, We've got the route assets Rob people the rock costs.

The opportunities there and we'll see that so I think the banks trust us for that.

My question is from Phillips Johnston with capital go ahead.

Operator: Our next question is from Phillips Johnston with Capital One. Please go ahead.

Hey, guys. Thanks last quarter you guys. Obviously, that's the plan rig counts for the year.

Phillips Johnston: Hey, guys. Thanks. Last quarter, you guys obviously cut the planned rig count for the year. Obviously, you mentioned the improved macro backdrop since then. I know the main goal continues to be free cash flow generation and pay down on the revolver, and it's probably a bit premature to talk about accelerating activity. What would you need to see to add one or more rigs back to the program at some point, either later this year or next?

Obviously, you you mentioned improve macro backdrop since then.

I know the main goal continues to be free cash flow generation and pay down on the revolver and it's probably been.

Later this year next.

Roland O. Burns: Well, I think that's a good question, you know, obviously, that's the first time people start talking about that. I think, you know, you still have, you know, relatively low gas prices. You know, I don't think you try to front run the improvement we see in the curve, you know. I think that, you know, as we assess next year, you know, we do see probably a little higher activity level, just, you know, based on the hedges we've already put in. I think we can support a 6 to 7 rig program. You know, as we look ahead to next year, we probably see a higher activity level.

Roland Burns: Well, I think that's a good question, you know, obviously, that's the first time people start talking about that. I think, you know, you still have, you know, relatively low gas prices. You know, I don't think you try to front run the improvement we see in the curve, you know. I think that, you know, as we assess next year, you know, we do see probably a little higher activity level, just, you know, based on the hedges we've already put in. I think we can support a 6 to 7 rig program. You know, as we look ahead to next year, we probably see a higher activity level.

But I think that's a that's a good question and fit if that's the first time people start talking about that but they add I think you still have relatively low gas prices. So I don't think you try to front run.

The improvement, we see and the curve and you know that I think that.

As we assess next year.

We do see probably a little higher activity level, just if based on our the hedges you've already put in and I think we can support.

Six to seven Red program and so as we look at the next year leases privacy or higher activity level, but.

Roland O. Burns: You know, won't commit to that or implement that until we're really seeing, you know, realizing prices that are, you know, much improved prices from where they are right now.

Roland Burns: You know, won't commit to that or implement that until we're really seeing, you know, realizing prices that are, you know, much improved prices from where they are right now.

Well commit to that and there are implement that until we're really in.

Yes.

Realizing prices that are you have.

But much improved prices from where they are right now.

M. Jay Allison: You know, the reason I love that question is because it shows that you've looked out into 20, you know, late 2020, 2021, and we get to talk about our almost 2,000 net locations that we have in the Haynesville-Bossier area. We are prepared with this inventory that we have, that we've demonstrated by drilling these on the 230-plus locations, really complete them since 2015. We're prepared for the future. We just need to have a little bit higher gas price, and we need to, you know, we need to pay down more on our RBL facility. We do need to get that paid down a little more.

Jay Allison: You know, the reason I love that question is because it shows that you've looked out into 20, you know, late 2020, 2021, and we get to talk about our almost 2,000 net locations that we have in the Haynesville-Bossier area. We are prepared with this inventory that we have, that we've demonstrated by drilling these on the 230-plus locations, really complete them since 2015. We're prepared for the future. We just need to have a little bit higher gas price, and we need to, you know, we need to pay down more on our RBL facility. We do need to get that paid down a little more.

The reason I love that question is because it it does it it's shows that you've looked at into 20 late 2000 2020 to 21 and.

We get to talk about almost 2000 net locations that we have in the same for Bogies area. So we are prepared with this inventory that we have there we've demonstrated by drill these under 230 plus locations really complete them since 2015, we're prepared for the future.

It'll have a little bit higher gas process, and we need to we need to pay down more on RBL facility, we do need to get that.

Hi, down a little more.

Yeah that makes sense and Jay I guess.

Phillips Johnston: Yeah, that makes sense. Jay, I guess, maybe if we can just get your latest big picture thoughts on industry consolidation and the Haynesville, especially given what's happened in the last couple of months with obviously much lower oil prices. You know, that you know, that improved macro backdrop on gas possibly over the next couple of years or so.

Maybe if we can just given your latest big picture thoughts on industry consolidation in the Haynesville.

Especially given what's what's happened the last couple of months with obviously much lower oil prices, but.

That that improved.

Macro backdrop on on gas, possibly over the next couple of years or so.

M. Jay Allison: Yeah. You know, again, we look in the world, you always have haves and have-nots, and we've all been on both sides of that. We've been on the have-not side for a long time with natural gas. I think when the Joneses came in, I mean, he's very good about looking around the corner. You know, you got to look around the corner to be where he is. As we looked around the corner in 2015, 2016, 2017, he looked around the corner of 2018, and we said, right or wrong, we really wanna be a natural gas company. That's where Ron said 97%, 98%, 99% of our production will be natural gas.

Jay Allison: Yeah. You know, again, we look in the world, you always have haves and have-nots, and we've all been on both sides of that. We've been on the have-not side for a long time with natural gas. I think when the Joneses came in, I mean, he's very good about looking around the corner. You know, you got to look around the corner to be where he is. As we looked around the corner in 2015, 2016, 2017, he looked around the corner of 2018, and we said, right or wrong, we really wanna be a natural gas company. That's where Ron said 97%, 98%, 99% of our production will be natural gas.

Yeah, you know again, we'd looked we yes again.

In the World you always have haven't have not from we've all been on both sides of that.

Ben all the have nots for long time with natural gas I think when the Jones just came in and when he is very good about looking around the corner you Gotta look around the corner to be where he is and as we look around the corner in 2015 16 17, he looked around the corner of 18.

And we said, we right or wrong, we really want to be a natural gas company and Thats, where Ron said 90 790, 899% of our production will be natural gas and then we had to say well is smart location location location not only drilling locations, but geographically word you located in ward.

M. Jay Allison: We had to say, well, it's like, you know, location, location, not only drilling locations, but geographically, where are you located and where do you have this midstream, that's a plus to you, not a negative. So as the Joneses look around the corner and, you know, we were there, hopefully showing them what we're seeing, you know, you end up with today. I think today, yeah, I do think that, you know, we've got 13 million barrels of oil in the US. You probably have five million of that in Texas. You see, you got 750,000 oil field workers in the US. You probably have half of those in Texas, and you're saying maybe half of those are gonna lose their job.

Jay Allison: We had to say, well, it's like, you know, location, location, not only drilling locations, but geographically, where are you located and where do you have this midstream, that's a plus to you, not a negative. So as the Joneses look around the corner and, you know, we were there, hopefully showing them what we're seeing, you know, you end up with today. I think today, yeah, I do think that, you know, we've got 13 million barrels of oil in the US. You probably have five million of that in Texas. You see, you got 750,000 oil field workers in the US. You probably have half of those in Texas, and you're saying maybe half of those are gonna lose their job.

You have this of midstream.

It's a plus to you not a negative.

So as John just look around the corner and we were there hopefully showing now what we're saying you end up with today and I think today.

Yes, I do think that we've got 13 million barrels of oil into us.

You probably have both Bob measure that in Texas.

You see I got 750000.

Oil field workers in the US you probably have a half of those are the in Texas, and you're saying maybe half of those are going to lose or job. It's a very tough market editor for oil and usually it will take 40 plus dollars for you to really want to drill oil for oil. So we look at data we have from.

M. Jay Allison: It's a very tough market out there for oil. Usually it'll take $40+ for you to really want to drill for oil. We look at that, and we have to look at the oil-side model before we look at the natural gas model. We look at natural gas, and we do look at LNG. We say, you know, maybe we lose a BCF or 2, but there is still a huge demand for LNG. There's huge industrial demand. Fortunately, the commodity that we have is not, you know, it's not a transportation commodity like oil is. I think it's cleaner on the carbon side. We think it's needed. We think it pushes coal out of the way a little bit, and it's probably a $2.80 to $3.15 commodity.

Jay Allison: It's a very tough market out there for oil. Usually it'll take $40+ for you to really want to drill for oil. We look at that, and we have to look at the oil-side model before we look at the natural gas model. We look at natural gas, and we do look at LNG. We say, you know, maybe we lose a BCF or 2, but there is still a huge demand for LNG. There's huge industrial demand. Fortunately, the commodity that we have is not, you know, it's not a transportation commodity like oil is. I think it's cleaner on the carbon side. We think it's needed. We think it pushes coal out of the way a little bit, and it's probably a $2.80 to $3.15 commodity.

Look at the oil SaaS model before we looked at the natural gas model, we look at natural gas.

And we do look at add LNG, we so you know might where there's a bcf or two but there is still a huge demand for LNG, there's huge industrial demand. Fortunately the commodities that we have is not.

It's not of transportation commodity like oil is so I think it is cleaner on the carbon side.

We think it's needed we think it pushes cold I will go away a little bit and it's probably a three to 82 to 315 commodity that's kind of the price range. We looked at and you asked a world where we would get a really excited you know you get a 280 to three dollar gas for us.

M. Jay Allison: That's kind of the price range we look at. You ask where we would get it really excited. You know, you get a $2.80 to $3 gas price, our cost structure with our opportunities we have, we're super excited. We just wanna maintain where we are. We wanna get better with where we are. We wanna demonstrate to the bondholders and the equity owners, and our stakeholders that we can manage this. We think there's some tough times. We don't see $22, $23, $32, $33 oil curing the problem for the oil side of the cycle. We think as this associated gas goes away, these pipelines are not built to service these oil fields, that we only become stronger.

Jay Allison: That's kind of the price range we look at. You ask where we would get it really excited. You know, you get a $2.80 to $3 gas price, our cost structure with our opportunities we have, we're super excited. We just wanna maintain where we are. We wanna get better with where we are. We wanna demonstrate to the bondholders and the equity owners, and our stakeholders that we can manage this. We think there's some tough times. We don't see $22, $23, $32, $33 oil curing the problem for the oil side of the cycle. We think as this associated gas goes away, these pipelines are not built to service these oil fields, that we only become stronger.

Our cost structure was our opportunities we have we're super excited we just want to maintain where we all we want to get better with where we are we want to demonstrate to the bond holders in the equity owners.

Our stakeholders that that we can manage this and but we think there's some tough time, we don't see 20 to 23 30 to $33 oil curing the problem for the oil side of the cycle and we think is this this associated gas goes away. These pipelines for not bill.

Our services oil fields that we only become stronger and I think we've become a little supercharge because of where we're located our economic screamed that we are.

M. Jay Allison: I think we've become a little supercharged because of where we're located. Our economics scream that we are, you know, high, high margins and low cost producer. That is our corporate attitude, and I think that's the Joneses' attitude.

Jay Allison: I think we've become a little supercharged because of where we're located. Our economics scream that we are, you know, high, high margins and low cost producer. That is our corporate attitude, and I think that's the Joneses' attitude.

Margins in low cost producer.

So.

That's it is our corporate attitude I think thats a jones's attitude.

Alright sounds good thanks, guys.

Phillips Johnston: All right. Sounds good. Thanks, guys.

Thanks.

M. Jay Allison: Thanks.

Jay Allison: Thanks.

Operator: Our next question is from Jane Trotsenko with Stifel. Please go ahead.

From James Pachinko with Stifel. Please go ahead.

William Hale: Hey, this is William Hale asking on behalf of Jane. You guys talked about completions cadence a little bit. Could you touch a little bit on CapEx and production cadence for the remainder of the year?

Hey, this is William how asking on behalf of Jane.

You guys talked about completions came to a little bit could you touched a little bit on capex and production cadence for the remainder of the year.

Sure and I think you, yes, given that completions are.

Roland O. Burns: Sure. I think, given that completions are, you know, more than half of the cost of these wells, we do see, you know, the Q2 being, you know, the lightest CapEx quarter and hopefully a good free cash flow generating quarter. You know, probably, it's not gonna be balanced spending for the rest of the year. I think, you know, you'll probably see the Q2 the lightest, and then you kind of, after that, kind of split the rest of the CapEx, you know, between the last two quarters as we, if we kind of return to the completion activity, you know, in Q3 like we currently plan to.

Roland Burns: Sure. I think, given that completions are, you know, more than half of the cost of these wells, we do see, you know, the Q2 being, you know, the lightest CapEx quarter and hopefully a good free cash flow generating quarter. You know, probably, it's not gonna be balanced spending for the rest of the year. I think, you know, you'll probably see the Q2 the lightest, and then you kind of, after that, kind of split the rest of the CapEx, you know, between the last two quarters as we, if we kind of return to the completion activity, you know, in Q3 like we currently plan to.

Yes.

Yes more than half of the cost of these wells, we do see yet.

Second quarter Ben.

Yes, the lightest capex quarter, and hopefully a good free cash flow generating quarter.

And then.

Probably add.

So it's not going to be balanced spending for the rest of the air I think that.

Your privacy the second quarter, the Leidos and then.

And any kind of after that kind of split the rest of the capex.

Between the last two quarters as weak.

If we kind of returned to the completion activity in third quarter like we currently plan to.

Got it thanks, and then my other question is could you comment a little bit on the industry activity level that you're seeing in aimco.

William Hale: Got it. Thanks. My other question is, could you comment a little bit on the industry activity levels that you're seeing in the Haynesville?

Sure I mean, I think we've seen that must be other.

M. Jay Allison: Sure. I mean, I think we've seen, you know, most of the other companies in the Haynesville are private that are actually running rigs other than a few. We do see that, you know, trending down a little bit. We've seen a few rigs dropped. I think the play, the activity level in the Haynesville is kind of a testimony to just how strong the economics are of these wells. I mean, you know. If you look at the basin, I mean, the basis differentials are very, very tight. Transportation is very inexpensive unless you've got, you know, unless you've contracted to, you know, way above market rates.

Jay Allison: Sure. I mean, I think we've seen, you know, most of the other companies in the Haynesville are private that are actually running rigs other than a few. We do see that, you know, trending down a little bit. We've seen a few rigs dropped. I think the play, the activity level in the Haynesville is kind of a testimony to just how strong the economics are of these wells. I mean, you know. If you look at the basin, I mean, the basis differentials are very, very tight. Transportation is very inexpensive unless you've got, you know, unless you've contracted to, you know, way above market rates.

Companies in the Haynesville, our private that are theyre actually running rigs.

Other than a few and we do see that.

Yes trending down a little that we've seen a few a few rigs dropped.

I think the play that activity level in the Haynesville is kind of that testimony that just how strong economics are these wells I mean.

Yes that that if you look at the basin I mean, the basis differentials are very very tight transportation is very inexpensive unless you've got.

Lets you've contracted two.

Way above market rates, which where we were less not to have the AD. So I think that I think the activity level in the Haynesville is that they love more resilient than some other plays because of the.

Roland O. Burns: We, you know, we're blessed not to have. I think the activity level in the Haynesville is a little more resilient than some of the other plays because of the strong IRRs that you have with the wells. You know, given that capital is tight for everybody and, you know, I think most of the operators for the most part wanna spend within cash flow or under cash flow. We've seen the larger, all but maybe one of the larger private operators really kind of pull back in, you know, kind of within their cash flow level, so.

Roland Burns: We, you know, we're blessed not to have. I think the activity level in the Haynesville is a little more resilient than some of the other plays because of the strong IRRs that you have with the wells. You know, given that capital is tight for everybody and, you know, I think most of the operators for the most part wanna spend within cash flow or under cash flow. We've seen the larger, all but maybe one of the larger private operators really kind of pull back in, you know, kind of within their cash flow level, so.

The strong ours that you have with the wells, but given that capital.

Capital as that tight for everybody and.

I think.

Nobody had I think most the operators for the most part what a spend within cash flow or under cash flow and so that as we've seen that the larger all that maybe one of the larger private operators really really kind of pull back and kind of within their their cash flow level. So you know today you have 31.

M. Jay Allison: You know, today you have 31 rigs that are busy in the Haynesville-Bossier. You have one private equity-backed company that has 8 rigs. You have four companies that have 4 rigs, and we're one of those four. Then the rest of them, they may have 1 rig or 2 at the most. It's 31. That's the last kind of count number we looked at.

Jay Allison: You know, today you have 31 rigs that are busy in the Haynesville-Bossier. You have one private equity-backed company that has 8 rigs. You have four companies that have 4 rigs, and we're one of those four. Then the rest of them, they may have 1 rig or 2 at the most. It's 31. That's the last kind of count number we looked at.

Rigs there are busy in the Haynesville bugs.

One private equity backed company that has eight rigs you have.

For companies that have four rigs and we're one of those four and then the rest of.

I have one rig or two combos. So its 31.

Thats the last kind of account number we looked at.

Got it thanks and then.

William Hale: Got it. Thanks. Just lastly, should we maybe model in some lower Bakken production volumes given the pricing up there?

Just last May should we maybe I'm modeling staying lower Bakken production volumes, given the pricing up there.

Yes, that's what Ron alluded to that basically we don't we.

Roland O. Burns: Yeah, that's what Ron had alluded to, that basically we have not seen it. We've seen reports of about 20% of our Bakken production being shut in, but we're kind of modeling 40% shut in just for the rest of the year, with it returning next year. Frankly, you know, we wish it was all shut in. I mean, because the prices are so low that there's really you know, that shut-in number has no impact on cash flow, and frankly, you'd rather preserve the reserves. We don't, we're all about operating on the oil side and have a lot of different operators.

Roland Burns: Yeah, that's what Ron had alluded to, that basically we have not seen it. We've seen reports of about 20% of our Bakken production being shut in, but we're kind of modeling 40% shut in just for the rest of the year, with it returning next year. Frankly, you know, we wish it was all shut in. I mean, because the prices are so low that there's really you know, that shut-in number has no impact on cash flow, and frankly, you'd rather preserve the reserves. We don't, we're all about operating on the oil side and have a lot of different operators.

Had we have not seen at we've seen reports of about 20% of our Bakken production being shut in but where we're kind of modeling, 40% shedding and just for the rest of year with that returning next year and frankly, you know where we wish it was all shut in the main because that yes. The prices are so low that theres really.

Yeah that shut at number has no impact on cash flow and frankly, the rather preserve the reserves, but we don't.

We're all that operate on the oil side and have a lot of different operators. So I mean, basically I think if you kind of track if your cover the Bakken in kind of see an industry trend. There you could probably apply that to our oil production and probably be close because we were.

Roland O. Burns: I mean, basically, I think if you kinda track, if you cover the Bakken and kind of see an industry trend there, you could probably apply that to our oil production and probably be close because we kind of have non-operated interest, probably with all the major Bakken operators kind of spread out. That's a good proxy.

Roland Burns: I mean, basically, I think if you kinda track, if you cover the Bakken and kind of see an industry trend there, you could probably apply that to our oil production and probably be close because we kind of have non-operated interest, probably with all the major Bakken operators kind of spread out. That's a good proxy.

We we patterns have not operate interest.

Probably with all the major Bakken operators kind of spread out so we're again thats a good proxy.

Got it thanks for any color.

William Hale: Got it. Thanks for the color.

M. Jay Allison: You bet. Thank you.

Jay Allison: You bet. Thank you.

You bet. Thank you.

And our next question is from.

Operator: Our next question is from Welles Fitzpatrick with SunTrust. Please go ahead.

Patrick with Suntrust. Please go ahead.

Hi, good morning.

Welles Fitzpatrick: Hey, good morning.

Born on the.

Roland O. Burns: Morning.

Roland Burns: Morning.

Welles Fitzpatrick: The shut-in production volumes that you guys highlighted, you know, they picked up a little bit, obviously. Are those largely due to third-party offset fracs, or is that something you control? With the reduction in basin activity, do you expect that to kind of tick back down to that sort of 2-3% that you've been in quarters past?

The shut in production volumes that you guys highlighted.

Picked up a little bit obviously are that's largely due to third party offset fracs or is that something you control and.

And with the reduction in in basin activity do you expect that to the kind of tick back down to that sort of two 3%.

Ben and course bad.

Yes. This is Dan so we approximately three quarters of the shut in production. We had in Q1 was due to offset frac activity.

Daniel S. Harrison: Yeah. This is Dan. Approximately three-quarters of the shut-in production we had in Q1 was due to offset frac activity. I'd say probably the biggest change in Q1 versus the previous quarters is a big majority of that was probably more than we usually average was due to offset operators. They just had a lot of activity nearby our acreage, some of our better production that we had to shut in. We did have a fairly large project we did over in the Elm Grove area that had, you know, that's a really good area, and we had to shut a lot of our good production in for that project.

Daniel Harrison: Yeah. This is Dan. Approximately three-quarters of the shut-in production we had in Q1 was due to offset frac activity. I'd say probably the biggest change in Q1 versus the previous quarters is a big majority of that was probably more than we usually average was due to offset operators. They just had a lot of activity nearby our acreage, some of our better production that we had to shut in. We did have a fairly large project we did over in the Elm Grove area that had, you know, that's a really good area, and we had to shut a lot of our good production in for that project.

And I'd say, probably the biggest change in Q1 versus the previous quarters is a big majority of that was.

Probably more than we usually average was due to offset operators.

They just have a lot of activity nearby our acreage some of our better production that we had to shut in.

We did have a.

Fairly large project, we did overlay on groom area that that to handle that's a really get area, we had to shed a lot of.

A lot of Oregon production and for that project. So it will definitely an abnormal quarter in that regard and we do see that being much lower for the rest of the year definitely in Q2.

Daniel S. Harrison: It was definitely an abnormal quarter in that regard, and we do see that being much lower for the rest of the year, definitely in Q2. You know, the good thing about what you see there is the quality of these wells that we've been bringing on. You see the sensitivity because these are really high producing rate wells. Any offset operator, you know, they shut in, we shut in. You can see this impact. The beauty of it is that it's not because we don't have quality wells, because we do have quality, and you can see the sensitivity. That's a, it's a good thing you can see it. I think we've cured it for the most part. The rig count has dropped from, you know, the 50s down to the 31, and a lot of these companies are doing what we're doing.

Daniel Harrison: It was definitely an abnormal quarter in that regard, and we do see that being much lower for the rest of the year, definitely in Q2. You know, the good thing about what you see there is the quality of these wells that we've been bringing on. You see the sensitivity because these are really high producing rate wells. Any offset operator, you know, they shut in, we shut in. You can see this impact. The beauty of it is that it's not because we don't have quality wells, because we do have quality, and you can see the sensitivity. That's a, it's a good thing you can see it. I think we've cured it for the most part. The rig count has dropped from, you know, the 50s down to the 31, and a lot of these companies are doing what we're doing.

You know the good thing about what you see there is the quality. These wells are we've been bring Ana.

You see this sensitivity because these are really hobbs producing rates wells and any offset operator, you know they shut in we shut in you can see this impact the beauty of is that it's not because we don't have quality wells because we do have quality you can see the sensitivities. So that's a good thing you can see it.

Thank with curative for the most park and the rig count has dropped from you know the fiftys down to that 31 and a lot of these companies are doing what we're doing there kind of waiting on completions.

M. Jay Allison: They're kind of waiting on completions, so.

Jay Allison: They're kind of waiting on completions, so.

Roland O. Burns: Well, I'd add that we've got more than adequate takeaway and regional basis differentials are really nice and tight. It's really just the frac activity and you know that will be you know especially as we go into May and June, we'll be at a pretty low level. We expect to get back to kind of normal you know you know you know normal kind of shut-in levels you know which are closer to, for us, 2% to 3% versus the 5%.

Roland Burns: Well, I'd add that we've got more than adequate takeaway and regional basis differentials are really nice and tight. It's really just the frac activity and you know that will be you know especially as we go into May and June, we'll be at a pretty low level. We expect to get back to kind of normal you know you know you know normal kind of shut-in levels you know which are closer to, for us, 2% to 3% versus the 5%.

What I'd add that when we had we've got more than adequate takeaway and regional basis differentials are really nice and tight.

So it's not it's really just that frac activity.

And that will be.

Especially in that as we go into May and June will be at a pretty low levels. So we expect that to get to back to kind of normal.

Yeah and.

Normal kind of shut in levels, which are closer that for us, 2% to 3% versus the 5%.

Okay. Okay perfect Yeah, no certainly certainly better shut ins then than what some of your Oh. Your oil. Yes, you are saying that was my point [laughter], yes, that's a that's a great was saying thank you.

Welles Fitzpatrick: Okay. Okay, perfect. Yeah, no, it's certainly better shut-ins than what some of your oil-related companies are saying.

M. Jay Allison: Yes. That was my point. Yes, that's a great way to say it. Thank you.

Jay Allison: Yes. That was my point. Yes, that's a great way to say it. Thank you.

Roland O. Burns: We do produce a little oil, you know, just outside of the non-operated part. That is more in our, you know, more on the East Texas side and, you know, maybe with Cotton Valley and other tight production. It's pretty small. You know, we have good storage capability, so, you know, we don't even wanna sell that. We will, you know, for operated oil, we're gonna kinda just store that, you know, so, you know, over the next two to three months, you know, and not just give it away.

Yes.

What.

Roland Burns: We do produce a little oil, you know, just outside of the non-operated part. That is more in our, you know, more on the East Texas side and, you know, maybe with Cotton Valley and other tight production. It's pretty small. You know, we have good storage capability, so, you know, we don't even wanna sell that. We will, you know, for operated oil, we're gonna kinda just store that, you know, so, you know, over the next two to three months, you know, and not just give it away.

We do produce a little oil you know that outside of that not operated part and that is that more and our.

More on the East, Texas side, and maybe with Cotton Valley. Another type production is pretty small, but we have good storage capability. So we don't even want to sell that so we will we will wait for operated oil we're going to kind of just store that you know so you know over the next two to three months.

Yeah, and not just give it away.

Understood and then it seems like the lateral links also crept up and one Q, obviously, it's great for capital efficiency amongst other things, we should we expect those kind of longer laterals moving forward or was that just a little bit of noise.

Welles Fitzpatrick: Understood. It seems like the lateral length also crept up in one Q. Obviously, that's great for capital efficiency among other things. Should we expect those kind of longer laterals moving forward, or was that just a little bit of noise?

No I think that you know it generally and he can see that at our Capex slide you can see that the.

Roland O. Burns: No, I think that, you know, it generally, and you can see that on our CapEx slide, you can see that as you and if you kinda look at the progression, you can see the lateral lengths are lengthening because as we had this, the a little lower program, I mean, we obviously focused on the longer lateral. They have the best returns, and even the wells drilled at year-end, you know, they're the longest. So I think you'll see the lateral lengths increasing, you know, kinda like the Q1 was a good proxy, you know, so really closer to averaging, you know, the high 8 to 9,000 feet, you know, per well.

Roland Burns: No, I think that, you know, it generally, and you can see that on our CapEx slide, you can see that as you and if you kinda look at the progression, you can see the lateral lengths are lengthening because as we had this, the a little lower program, I mean, we obviously focused on the longer lateral. They have the best returns, and even the wells drilled at year-end, you know, they're the longest. So I think you'll see the lateral lengths increasing, you know, kinda like the Q1 was a good proxy, you know, so really closer to averaging, you know, the high 8 to 9,000 feet, you know, per well.

As you and if you kind of look at the progression you can say the lateral lengths are are lengthening the head as we as we had this as the the although lower program I mean, we obviously focused on the longer laterals. They have the best returns and even the wells drilling at year end you know there there the longest so.

I think you'll see that lateral lengths.

Increasing.

Kind of like that the first quarter was a good proxy, yes, I really closer to averaging in the high eight.

To 9000 feet per.

Roland O. Burns: Usually, we only do a shorter lateral if it's something that's needed to kinda finish up an area, and it's the only real way to. It's already established where you can't create a long lateral in the future.

For wells so.

Roland Burns: Usually, we only do a shorter lateral if it's something that's needed to kinda finish up an area, and it's the only real way to. It's already established where you can't create a long lateral in the future.

Usually we actually do shorter lateral if it's just something thats needed to kind of finish up in area and that's the only real way to its already is already established where you can't create a long lateral in the future.

Thanks, so much.

Welles Fitzpatrick: Thanks so much.

And as a reminder to ask a question simply press star one on your telephone keypad.

Operator: Okay. As a reminder, to ask a question, simply press star one on your telephone keypad. We have no further questions at this time.

Yes.

And we had no further questions at this time.

I guess in closing again as I mentioned earlier it is a pretty crowded agendas to those reviews that are still here. Thank you.

M. Jay Allison: I guess in closing, again, as I mentioned earlier, it is a pretty crowded agenda, so those of you that are still here, thank you. Our commitment to you, our stakeholder, is to continue to manage this business properly through very difficult times. We're gonna be patient, yet we are going to seize opportunities as they surface, and they make us a better company. Thank you for your time, and thank you for your trust.

Jay Allison: I guess in closing, again, as I mentioned earlier, it is a pretty crowded agenda, so those of you that are still here, thank you. Our commitment to you, our stakeholder, is to continue to manage this business properly through very difficult times. We're gonna be patient, yet we are going to seize opportunities as they surface, and they make us a better company. Thank you for your time, and thank you for your trust.

Our commitment to you our stakeholder is to continue to manage this business properly so very difficult times, we're going to be patient.

Yes, we are going to seize opportunities as they surface and they make us better company. So thank you for your time.

And thank you for your trust.

Thank you again for joining US today. This does conclude today's conference call you may now disconnect.

Operator: Thank you again for joining us today. This does conclude today's conference call. You may now disconnect.

[music].

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