Q4 2019 Earnings Call

The company's total net production hit an average of $145 million cubic feet of natural gas and equivalents per day in the fourth quarter and for the full year net production grew year-over-year by 85%

Reserves at year-end averaged approximately 2.5 BCF per thousand feet of lateral for all of our higher profit tighter flak animal space Wells that we have drilled over the last three years.

Performance from our refine completion designs lower cost of goods and services very low l o e and our heads position are collectively delivering very solid returns.

For 4 year, 2019 our return on Capital employed or r o c e was approximately 12% I will show you how that compares with our peers in just a moment.

Solid production performance Cost Containment and approximately 3.4 million dollars of realized heads benefit delivered even in the fourth quarter of approximately $21,000 for the full year. We achieved $79 in ebitda.

We again delivered top-tier Capital efficiency while maintaining low leverage on our balance sheet.

That's why we present our year end 2019 SEC proved reserves which grew to 517 BCF with a present value of juice or three hundred million dollars using SEC mandated pricing and discounted at 10% as you'll see from the pie charts are proved reserves are almost exclusive or natural gas and associated with the core Haynesville Shale assets.

At 6 we provide an updated cap table as of the end of the year a year end. Total net debt was $104 million dollars with approximately $93 outstanding under our seen a credit facility, which currently has a borrowing base of 125 million dollars.

Turning to slide seven. We provide our quarterly production chart which shows the continued growth we have achieved and as I mentioned averaged $145 million cubic feet of gas per day in North quarter. In addition. We provide the midpoint of our current plan and guide us for 2020.

What's a lot of eight we provide detailed volume and price information on our current natural gas and crude oil positions as you can see we are very well has through all of this year with a combined seventy million cubic feet of natural gas hedge that a blended average fourth floor price of $2.60 per mcf which provides solid protection against the Catholic depressed natural gas market we continue to watch the natural gas markets closely for additional opportunities to add to our hedge position to both support and protect our Capital. Finally. We provide our current twenty twenty guidance on slide eight which provides for more modest year-over-year growth with a projected midpoint of production equal to an average of 149 million cubic feet of natural gas and equivalents per day on a capex program with a midpoint at sixty million dollars.

We have also updated.

A guide us for the expected basis differential in the Haynesville as well as estimates of our 20 20 per unit cash cost on a per mcf e basis and in addition, we do provide a participated well count and completion caters for you on a quarterly basis. Now turn the call over to Rob thanks Gill stated earlier production averaged approximately 145 million cubic feet equivalent per day in the fourth quarter, which was at the high end of our previous guidance range of 140 to $145 million cubic feet equivalent per day primarily driven by the participation in a non-operated. Well in the quarter that was unexpected at the time of our previous guidance.

Revenues adjusted for cash-settled derivatives total of 33.6 million for the quarter comprised of 30.2 million of oil and natural gas revenues and 3.4 million of cash settled derivatives are per unit cash operating expense, which is defined as per unit operating expenses in excluding d d n a non-cash GNA dropped to ninety seven cents per ncfe in the quarter generating a cash margin of 62%

capital

Pictures for the quarter told 18.5 million of which 99% was spent on Drilling and completion of costs associated with Haynesville Wells the fourth quarter cup of expenditures were higher than our previous guidance again due to the participation in one previously unanticipated non-painful. Well in the quarter Capital expenditures for the year totaled ninety-eight point four million and ninety-nine percent on Drilling and completion costs in the Haysville. We conducted drilling or completion operations on 16 gross wells in 2019 and added three gross 1.85 net and 9 gross 7.2 net Wells during the quarter and year respectively off.

We previously gave guidance for 2020 in December, but it's Gil said it is subject to quarterly review by the company's board of directors with the primary goal of being cash flow generation Chef modest growth in volumes head realizations and a continuing reduction in cash operating expenses interest expense total two million in the quarter which included cash interest of one point two million incurred on the company's revolver and non-cash interests of $800,000 incurred on the company's convertible notes.

the non-cash

Interest expense was comprised of $400,000 of paid in kind interest in $400,000 of amortization of debt discount in debt issuance Costco primarily associated with the company's secondly notes moving back to our slide deck as we have highlighted before we've included several slides beginning with slide ten that show how we compare to our peers.

As stated earlier and as you will see on slide nine, I return on Capital employed for the year was 12.4% despite very low commodity prices which ranks fourth out of the thirty nine companies in our prayer group that have reported fourth-quarter financials as of Tuesday.

In addition to returns it is critical to maintain low leverage in these challenging times for commodity prices and we are focused on maintaining a debt-to-ebitda ratio of one point five times or lunch and we're below this marker currently and expect to remain there in the foreseeable future.

Even though our Capital efficiency and return on Capital employed or near the top of the peer group in our debt-to-ebitda size conservative. We only trade at approximately two times Enterprise value-to-ebitda shown on slide 12th, which needless to say is an extremely low multiple versus our peer company average of over four times.

Is everyone likely Knows by now? All of our current activities are centered in the core of the Haynesville beginning on slides 13 and 14. We entered twenty-twenty with 22,000 acres in a core of the play and 208 gross 91 net local locations on spacing of 880 feet between well bores for a net inventory life of approximately 16 years at current pace is Gil stated earlier these 208 gross 91 net locations are all in the core of North Louisiana. Our acreage in Louisiana is over 70% undeveloped and 73% operated.

we upgraded our

Region expect to continue to swap acreage or drill joint Wells with all set operators to maximize our returns.

We estimate over 1 TCF observe exposure at 2 and 1/2 BCF 4000 feet of lateral and eight hundred foot spacing in North Louisiana alone versus year and nineteen book Reserve in North Louisiana. And those are proved reserves of approximately 510 BCF equivalent. We also maintain approximately 3000 acres held by production in a in a river trend of the Shelby trial for future development.

The Haynesville and Bossier formations are both perspective on our Angelina River Trend acreage.

It's shown on slide fifteen. All of our acreage has now been dearest and we are in development mode drilling predictable wells in proven areas and connecting these Wells into existing pipe bomb with excess capacity.

We've allocated approximately 90% of our 2020 preliminary capital expenditure, but budget to Bethany Home Street and the other 10% to The Thorn Lake area.

We continue to outperform our type curves and on the slide 16. We are tracking our wells versus three hundred nine hundred forty six hundred foot lateral industry Wells drilled in the core.

Industry pumped an average of 3100 lbs per foot on these 309 Wells but as you can see, the older Wells are underperforming. The newer Wells is average profit is lower on Thursday is older Wells are six Wells shown in green were stimulated with approximately 4100 pounds of profit per foot and Tighter cluster spacing and interval spacing month. And not only are they quite a bit better than the industry average composite could occur, but our composite curb exceeds are two and half thousand foot curve to an estimate of approximately 2.7 BCF 4,000. There's a clear correlation between profit loading and cluster and interval spacing and we expect our more recent Wells to pull up the composite came over time as we reached completion optimization open the last 18 months.

flight 17

Reflects our 7,500 foot curve where we now show a composite of 225 industry Wells with average profit and concentration of approximately three thousand pounds per foot off the most part fits our 2 and 1/2 BCF per thousand foot type curve. The older Wells included in the industry composite curve that are underperforming the curve in the later years are a handful of under-stimulated Wells with profit loading of approximately twenty three hundred pounds per foot like the $46 foot laterals are more recent operated 7,500 footwells are outperforming materially the composite estimate of approximately 2.8 BCF 4,000 feet due to higher profit and concentration and again tighter cluster back in double spacing.

Slide eighteen which now shows a composite result from 225 10,000 laterals with an average of 3000 pounds per foot of profit are for the most part tracking are two thousand four thousand foot type curve. The older Wells here with lower prop and concentration kick in a little over two years out and are falling below the age once again tight correlation with loading any you are are nine Wells which averaged approximately 9600 feet of lateral and 3500 pounds per foot or for the most part tracking are 2 and 1/2 DCF 4000 curved. We believe our well performance speaks for itself and is driven by a number of factors qualities are encouraged and no question. We were in some of the best rock in the play and Optimum completion methodology where profit concentration cluster and interval spacing and pump rates providing material.

difference in results

Callback technique that minimizes daily drawdown flattens of the decline curves provides. Hi recoveries of gas in place and most importantly maximizes returns Thursday. We have updated our economics and shown as shown on slides 1921 reflect our outperformance and to also include a $2 gas price off on the low end of the range.

Our economics have improved on our forty six hundred and seventy five hundred foot laterals do to outperformance as you can see even at $2.25 gas price. We can offer a 40% irr on our average seventy five hundred foot lateral Wells as a reminder. The Hazel economics are driven by high volumes attracted Netflix off of to Henry Hub as compared to other gas basins low service costs low lifting costs and Severance tax abatement until the earlier of two years or pay out of the world.

in summary

Although we can't control commodity prices. Our team is executing. Well, our balance sheet is in good shape with low debt metrics. We have a nice hedge position that is minimizing our commodity price risk month and a unit cost structure that is declining creating competitive margins.

With that, I'll turn it back to Nick for Q&A.

I'll begin the question-and-answer session to ask a question. You may press star than one on your touchtone phone for using the speaker phone. Please pick up your handset before pressing the keys withdraw your question, please press * then two.

This time we'll pause momentarily to assemble our roster.

First question comes from done back in time for Johnson rice, please. Go ahead.

Morning, Robin Gill. I want to know what if you could provide a little more color around the optionality in your 2020 program, you know, just running one rig is it would it be prices do remain lower would it be laying that rig down for a while and you know, maybe picking up a looking for some more not opportunities or kind of how do you how do you think about that? It would obviously free cash flow kind of be involved in this environment. Yeah. This deal has gone. Well, lots of great flexibility. We do have some areas, you know, Rob alluded to in his prepared remarks. We had a kind of an unexpected non proposal come up to us on really good acreage and we didn't want to let that opportunity to get away. So we we elected to participate in that. Well, we have several of those that could be potential opportunities in 2020 and we're still trying to get our arms on the exact timing of that. We will backfill around with our Alfred activity for whatever that level of

No, not participation is that being said we got great flexibility and we're running the one rig now. I think one of the things that we could do is

Is maybe just build some ducks? Keep the rig for a period of time a few ducks and complete them indicators that make sense with natural gas prices. So as I alluded to in my remarks will be reviewing a number of different scenarios with the board next week, um and and staying with the base case guidance. We provided is one of those options obviously and then we may decide that we want to slow down a little bit. I really don't think you'll see a pick up the pace at this point in time and and miserable I'll add to that as far as swaps. We should continue to do that. We think there's a chance of perhaps picking up a little bit of incremental, you know, bolt-on type Acquisitions through certain swamps, but nothing defended to to talk about now.

Okay, great. Thanks. And then maybe from a little bit higher level Mac or a question. You know, the Haines will recount was surprisingly resilient through the back half of nineteen and recognizing that private owner operators drove a lot of that but kind of what are you seeing now? And how do you think about the Pains of activity in context of kind of the broader natural gas space and what what your thoughts on kind of looking out of 18 months with respect to price and kind of ideology maybe at low prices fixable at prices. Just going to any color you can get there and how you lost our money. Obviously I crystal balls not necessarily any better than anyone else's we will say that we track all Haynesville activity very closely on a weekly basis. We are home and sculpting that too. Specific hangs will only rigs sometimes if you look at just kind of general areas, you'll pick up some Cotton Valley activity and non Haynesville stuff.

Our our internal numbers suggest that the change already hit about 60 Riggs at a peak last year and the most recent week. It's at 38. My personal belief is

Number comes inside of thirty and probably does fairly soon, uh and and will be ultimately this year will be one of those rigs. I believe it would be would be laying down a rig and building some ducks as I said and and completing some wells later in the year. I can't help but believe given we're a natural gas prices and stripped prices are off while most people are fairly. Well hedged this year that begins to change quite dramatically in 2021. And as we move closer and closer to Twenty-One, either the scripts going to suck up or Catholics levels are going to come down in terms of natural gas activity. And the only thing I'll add done is we belong to a Consortium which includes most of the operators in North Louisiana, and and the commentary is is consistent with what Gil just described which includes quite a few privates that that people, you know don't wage.

Teligence on so the direction is clearly rigs coming out of the base and which we think obviously is a a real positive on on on declines and Supply off not just there but you'll see them continuing in the Marcellus which ultimately, you know, fixes the commodity the strip ought to go in contango and then you'll you'll have a a real reasons for people to kind of jump back into the space.

I agree.

Thanks and congrats on a strong nineteen and a solid 20 Outlook. Thank you.

Next question comes from Wells with Patrick of SunTrust, please go ahead.

Hey, good morning. Good morning. Pay Wells. Can we talk a little bit more about the the Divergent and and the curves on the lateral length? I mean more specifically I'm a little bit surprised at the mid-ranger would be better than than than the 10,000 footer. You know, how how I guess how clean is that data? I mean, it's you know, how many Wells do you have in each in each sample set and it's some of that may be a uh, kind of kind of a the fact that you don't you don't necessarily have asthma may be 4,600. Does he do ten thousand Footers Etc?

Yeah, so this Rob I'll take I'll take a shot at that it look at so for example, the forty six hundred foot lateral long as the newer Wells flow through the curve. We think that that composite result is going to only get better and you can see that over the first six months. Those Wells are producing far in excess of the older Wells, you know the kick in and call it twenty months. So we all we've done is taken the positive as well as that we show on that graph and model that out using standard, you know, terminal decline rates as used by Netherland Sewell wage. But but we think there's upside to the forty six hundred foot case up and above over and above the 2.7 BCF 4,000 that we've used in the bath.

economics

Will tell you one other thing that we that we see some benefit there, which is the ability to to nail your Capital expenditures, you know, right on your AFV. Obviously the the shorter the ladder all the higher the probability of meeting or beating those cost estimates as to the 7,500 would make great progress there. That's that those economics have moved a good bit the previous economics, for example

On a 7500 foot lateral, we're 45% irr at $2.50 and that's you know, 59% now so really almost 15% include July are are and like the the 46-foot laterals. We started tightening up our Frac interval spacing increasing our profit loading a bit and similar to the 4604 curve. You see over the early eighteen months. Those Wells are outperforming and again should pull up the the curve over time as long as well scroll through the curve. So we we feel very good about that. When you look at the the ten thousand foot lateral, you know, we have similar profit probably that than what we have before the, you know, the the profit loading again is dead.

if some in a similar

Range, the the interval spacing on average is about 125 feet per stage versus a little less than that on the 4600 s. So again, and and even the 7,500 the the better Wells that pull it up or even tighter than that at a hundred foot intervals. So clearly, you know, when we do linear regression very good correlation, a non-profit four foot and interval spacing per foot and we think that's shown up here the only problem with tightening your intervals on the ten thousand foot laterals to a hundred feet 610. It's just the cost of the well and as we've talked before anytime you extend past $7,500 fee. If you have a need to trip out a whole and replace bottom whole assembly or or bit. You're you're adding to your cost of the web or so and it's you know, three or four day turn off.

So we you know all things being.

An equal you could you could say your $7,500 or your sweet spot in that you have less risk on exceeding your AFV and you're generating very good rates of returns that are actually similar if not better than your ten thousand foot laterals because the results have been better.

Okay. Okay, that makes sense. It sounds like the $4,600 have probably the most the most room to to improve versus versus the rest of them. What can you remind us how many wage many of your locations are are seven thousand foot or or or greater? Yeah. It's a moving Target. You know, I I would say depending on how we structure that you could probably get, you know forty fifty percent longer laterals and then the forty six hundreds, you know would be, you know, call it off at 50 to 60 that being said with acreage swaps. We've been drilling longer laterals. So I think the likelihood is that it could be as you know, be more like a third a third Thursday, but we've but if you just grid it out right now we have we have, you know, plenty of $4,600 to the drill and that's why you know spending. Yep.

Our our well cost.

You know in some cases or probably slightly higher than others, but we're outperforming those other companies because of are well-designed and when you really do the math and based on the economics, yeah, you can save money by pumping less profit and you're going to automatically make poorer Wells and we just see the real benefit from from The Profit loading and the month interval space. Okay. Okay that that makes sense. And then, you know kind of look into twenty-twenty you talked about this a little bit but off-key. Can you talk to the non up visibility from a Cat-Back standpoint? And I I assume giving your prior comments that said if anything that that would be biased downwards.

Yes, this is Gil. Well, first of all, it's very difficult to to give you a whole lot of clarity because as we just happened in this last quarter, we had something popped up wage didn't even know it was it was some activity on some acreage that the well proposal just came out of nowhere. And so we don't expect very much of that this year. We think that what's coming we do see we're still trying to get our arms around the exact timing of that. And as I said, we've got the flexibility with the rig and more importantly the case in a casing and completion Cadence to kind of backfill around that from a from a capital perspective and and blend it out on a quarterly basis.

Okay, perfect. That's that's all I have.

So much thanks Wells.

Next question comes from Philip Johnson Capital One, please. Go ahead.

Hey guys. Thanks. And thanks for the disclosure around p d p 10 a year end. I think it's speak to the yeah, I think it speaks to the value here. My question is how long approximately six hundred million of PDP value look like if you ran it at sort of a flat $2 gas price instead of it as you see dekhte. Yeah, we've not done the sensitivity yet. We've been dead, you know kind of running around with our head cut off getting ready for the for the the 10K and the call. I'll have to get back with you on that sensitivity Phillipsburg.

Okay, Rob and then you guys give it some good color around just the quarterly Cadence of network pops for the year. So just wanted to see what that schedule means for for Corley volumes of leads from a direct standpoint. I think your guidance implies full year average that's around 3% above kind of that fourth-quarter 19x atraight. So should we expect fairly even you know quarterly sequential growth throughout the year versus that exit rate or is there some lumpiness in program there is going to be a little lumpiness because if you look at the slide number nine current month has you know has its only completing one net. Well in the first quarter and then 22.3 net in the second 1.8 and 1/3 and and 7 in the fourth. So Monday is our budget currently sits, you know going to be a surge kind of in the second and third quarter and we'll we'll try to give a little bit more guidance is Gil said wage.

a board meeting next week and we'll

We'll see if if this change is at all. But but yeah, it'll be it'll be it'll certainly would be lumpy and peeking in the second and third quarter. Okay. So for q1 should expect maybe down a little bit and then surging in second and third quarter and then maybe down a little bit and Q4. Yeah exactly right directionally. Okay. All right. Perfect. Thanks Rob. Thanks Phil.

Next question comes from Parx poker and Palmer, please. Go ahead. Good morning morning.

I just want to check and see if you touch on this already. But the the knob well that you had in fourth-quarter. What was the working interest on that?

Yeah, like close to 25% working interest, but we incurred all the capital in December. So and and that dog by the way was kind of near the Louisiana border in East Texas. If someone else called me and said, you know, it looks like you had a increase in reserves in East Texas. It would basically just our interest from that will

God

Gotcha, and just sort of thinking of all the volatility we've had in commodity prices and it as you look ahead to the wrong sort of longer-term gas landscape, you know with with oil having taken, you know, having a tough time again with the the recent events. Do you have any assumptions about just what the associated gas, you know input into the system from the the Permian, you know what that would look like and if you know, for example, if we were headed for a considerably weaker environment for oil and it, you know, we saw activity slow say beyond what you know, have they expecting for the next couple of years. Do you think that would have a affect either regionally on on prices for you or or even on the Benchmark itself dead?

Yeah, this Rob. I'll take first stab at it. You know, we we've seen and we have a we have hedging Consultant Group that that advises on some of that and I think the numbers are really moving if you take a million barrel-a-day growth in the Permian which we would buy a slower than that based on where prices are where you know how conservative the banks are the capital markets being somewhat closed. We we think it's going to be less than that and we've seen you know 3 and 1/2 vfc a day or or thereabouts of associated gas growth if my memory serves me for the million barrel-a-day which which you know, we we think should be biased low. And of course the problem is the takeaway is not there to capture all those volumes. So we we think you know, you know the true output coming from the base and is going to be a good bit lower than that if you then look at the Haynesville and yep.

was currently in Decline and we

Don't think it's freeze off. It's certainly not in in the Haynesville. Maybe there's a little bit in the Marcellus. We think it's more cutting of capex budgets to live within their means then then clearly were declining there and we're going to have less Associated gas and as long as demand remains and it's certainly cologne says and help and and we're suffering through some oversupply on LNG currently as long as that kind of gets back to where where we think it should be in the back half of this year ought to be better for for gas prices and and and likely for oil prices as well. And as I said, you know guilt could try it. But my you know, what we really need is people to live their manes. Let's see the the rollover continue on Supply and then they'll reach a point in time where where we think this trip will go and contain go then then the the phone number.

History is more investable at that point.

Great. Thanks a lot. Thanks. No.

Can I hope you have a question, please? Press * then 1.

This concludes our question-and-answer session. I'd like to turn the conference back over to mr. Gill Goodrich for any closing remarks, please go ahead. Thank you very much everyone. We appreciate your participation this morning, and we look forward to reporting our first quarter $2,000 Sports theater Lemay. Thank you.

Conference is now concluded. Thank you for attending today's presentation. You may now disconnect.