Goodrich Petroleum Corporation
Q1 2019 Earnings Call Transcript

Published: 8 May 2019

[Operator:]

Good morning, and welcome to the Goodrich Petroleum First Quarter 2019 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Gil Goodrich, Chairman and Chief Executive Officer. Please go ahead.

[Walter Goodrich:]

Hello, and good morning, everyone. Thank you again for participating in our first quarter earnings call this morning. We are pleased to have a chance and the opportunity to share with you our result and the variety and update on our current activities as well as the plans we have for the rest of this year. In conjunction with the call, we've again prepared a slide presentation, and we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on the Goodrich Petroleum website entitled 1Q 2019 Earnings Presentation. During the first quarter, we continued to make good progress towards our stated goals and objectives for 2019. As outlined in our previous full-year guidance, we expect production volumes to double in 2019 versus 2018 on a preliminary capital expenditure budget of $90 million to $100 million. While these are our current plans, we maintain great flexibility to accelerate or decelerate our levels of development activity based on market conditions and quarterly review and approval by our Board. Based on the preliminary plan and with the strong hedge position, we currently have 100 million cubic feet of gas per day hedged for the remainder of this year at $2.89 per Mcf. We expect full-year EBITDA will be within the same range as the capital expenditures. Working towards that objective, we added to production our case index and 3H and 4H wells at Thorn Lake in Red River Parish of North Louisiana in the middle of the first quarter, which provided sequential production growth during the quarter. More importantly, however, since the end of the first quarter, we have added 3 outstanding wells, including our Loftus 27 and 22 1H and 2H wells, which are 7,500-foot laterals with a combined gross initial production rate in excess of 50 million cubic feet per day as well as our MSR Hunt 5H-1 in the Bethany-Longstreet Field of DeSoto Parish, which is a 4,600-foot lateral with an initial production rate of approximately 17 million cubic feet per day. Collectively, these 3 wells' initial rates have added over 40 million cubic feet of gas per day to our net production volumes and resulted in a current net production rate in excess of the midpoint of our full-year 2019 production guidance. I will now turn to the slide presentation for those of you would like to follow on, and our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2. On Slide 3, you'll see a brief overview of the Company which includes highlights of our core Northwest Louisiana Haynesville shale position where we maintain a 10-year inventory of delineated development locations at the 2019 rate of development. While we maintain upside exposure to crude oil in our Eagle Ford and TMS access our entire activity and plans are focused on the Northwest Louisiana Haynesville position which provides us the opportunity to dramatically grow production volumes while expanding our cash margin, maintaining conservative debt metrics and realizing top tier full cycle returns. Production during the quarter grew to an average of 104 million cubic feet of natural gas and equivalents per day, which resulted in quarterly EBITDA of $15.2 million and net income of $450,000. With the solid well results and subsequent to - that occurred subsequent to the end of the first quarter, this morning, we are providing production guidance for the second quarter in an expected range between 135 million and 142 million cubic feet of natural gas and equivalents per day. On Slide 4, we again highlight our year-end 2018 SEC proven reserves of 480 Bcfe, which had a present value of 10% of $418 million. On Slide 5, we show the cap table as of the end of the first quarter. During the quarter, we had modest incremental borrowings under our senior credit facility with $32 million drawn at the end of quarter and approximately $55.5 million outstanding on our second lien PIK notes or total debt of approximately $87.5 million. Subsequent to the end of the quarter, we have reached agreement on a new credit facility, which will have an initial borrowing base of $115 million, a $40 million increase over our current borrowing base and we anticipate finalizing all legal documentation next week. Initially, we plan to use a portion of the increased liquidity under the new facility to redeem these outstanding second lien notes, and concurrently, we plan to issue a new second lien note of a significantly smaller size or approximately $12 million on relatively similar terms with final documentation also expected next week. We believe these two transactions are important steps forward for the company, further improve and simplify our balance sheet and are reflective of the progress we've made over the past 2.5 years. Turning to Slide 6. Here, we illustrate the exceptional growth potential as we had been able to achieve over the past 2.5 years, the new guidance we are providing for the second quarter and our full-year guidance. All of the production growth and guidance is a result of the exceptional wells being drilled today in the Haynesville shale of Northwest Louisiana. On Slide 7, we provide detailed information on our 2019 guidance, which includes the production guidance for the full-year of 135 million to 145 million cubic feet of natural gas and equivalents per day based on the CapEx budget of $90 million to $100 million as I mentioned previously. In addition, the guidance provides the anticipated ranges for our expected gas price differentials or basis for our Haynesville shale production, per unit expenses for LOE, taxes, transportation and cash G&A. For modeling purposes, we also provide the expected level of activity, allocation within the core Haynesville areas and the quarterly cadence of completion activity with a total of approximately 11 gross and 10 net wells planned to be completed in our 2019 budget. Finally, and before I turn the call over to Rob, we believe hedging is an important and fundamental part of our business strategy and we have built in meaningful downside protection with our existing 2019 hedge position. The 100 million cubic feet per day of hedges for the balance of this year at $2.89 not only provide good protection during periods of soft pricing, but also provides for an exceptional rate of return on our capital program as Rob will highlight for you in just a minute. And with that, I'll turn the call over to him.

[Robert Barker:]

Thanks, Gil. Revenues more than doubled from the prior year period to $29.1 million with an average realized price of $3.12 per Mcf equivalent comprised of $2.91 per Mcf and $59.45 per barrel of oil. When including our cash settled derivatives, our average realized price was $2.93 per Mcf equivalent. Our per unit cash operating expense continued to drop in the quarter and we expect that to continue as Haynesville wells are added as these wells carried very low LOE and no severance tax until the earlier of payout in two years. As we shipped more capital in 2019 to our operated areas of Bethany-Longstreet, you will also see lower transportation fees flow through the income statement. Transportation expense in the quarter was higher due to the new wells added at Thorn Lake which carry a higher transportation expense, but the walls added since the quarter end are Bethany-Longstreet and carry a lower rate. As we have said before and show in our completion cadence, our capital expenditure program for 2019 is a little more first half loaded than second half loaded and CapEx for the quarter of approximately $30 million or about 30% of the midpoint of our 2019 preliminary budget of $90 million to $100 million was consistent with our plan. Interest expense totaled $3.7 million in the quarter which included cash interest of $500,000 incurred on the company's revolver and non-cash interest of $3.2 million incurred on the company's convertible notes. The non-cash interest expense was comprised of $1.8 million of paid in-kind interest and $1.4 million of amortization of debt discount. Moving back to our slide deck, as we have highlighted before, we have included several slides beginning with Slide 9 that show how we trade relative to our 48-company peer group. Review of Slides 9 through 11 will show you that the company still trades at a very cheap valuation, a little over 2x 2019 consensus EBITDA. Add the fact that we expect to maintain our debt-to-EBITDA metric through 2019 at 1 to 1.5 turns allows for a compelling argument as to why the company is undervalued. What is driving our significant growth in volumes and cash flow is our capital efficiency as shown on Slide 11. As we have previously stated, typically, capital efficiency is shown as a relationship of CapEx to growth in volumes which if used here would have us in the number one position, but we think it is more meaningful to show CapEx growth in EBITDA since we and the investment community are focused on returns, not exclusively growth in volumes. As you see, we ranked the third best company in our peer group at this capital efficiency metric, including Permian companies. It testifies that how our Haynesville Wells are generating superior returns regardless of the commodity, and I will walk you through our economics shortly. On Slide 12, and 13 we have approximately 214 gross, 99 net locations in North Louisiana with an average lateral length of approximately 6,600 feet currently, which as Gil said earlier equates to a 10-year drilling inventory based on our 2019 CapEx plans. Our North Louisiana acreage is approximately 80% undeveloped and 73% operated. We have girded our acreage with a plan to maximize long laterals and expect to continue to swap acreage or drill joint wells with offset operators to further increase our long lateral inventory and operatorship percentage. We estimate over 1 TCF of reserve exposure at 2.5 Bcf for 1,000 feet of lateral in North Louisiana alone. Moving to Slide 14, there continues to be approximately 50 rigs running in the basin, which again is evidence of the economics associated with the play. All of our acreage has now been derisked and were in development mode, drilling predictable wells in proven areas and connecting those wells into existing pipes with excess capacity. We've allocated approximately two-thirds of our 2019 capital to Bethany Longstreet and the other one-third to the Thorn Lake area and Red River Parish and we have exceptional wells that are offsetting all of our acreage part. We continue to show an abundance of well results on our declined curve slides beginning on Slide 15. On Slides 15 and 16, we are tracking 59, 4,600-foot laterals with average profit of approximately 3,400 pounds per foot with two years of production on 28 wells as well as our five operated wells. The composite production curve is generally following our 2.5 Bcf per 1,000-foot type curve as shown in red and our five operated well average is running well above the curve with higher proppant loading and tighter interval spacing. Slides 17 and 18 reflect our 7,500-foot curves where we continue to show a composite of 87 wells with average proppant concentration of 3,100 pounds per foot, which again fits nicely with our 2.5 Bcf per 1,000-foot type curve. The older wells included in the composite curve are a handful of under-stimulated wells and we expect the composite tail results to pull up as the newer wells with higher proppant concentrations flow through over time. Our more recent operated wells, which carry higher proppant concentration are running above the high case curve. Slides 19 and 20, which show composite results from 35 approximate 10,000-foot laterals with an average of 3,200 pounds per foot of proppant are also tracking our 2.5 Bcf per 1,000-foot type curves. Our 7 wells, which average approximately 9,800 feet of lateral and 3,400 pounds per foot of profit or for the most part tracking are 2.5 Bcf per 1,000 curve as well. Our operations team continues to form very well as evidenced by Slides 21 through 23 where we are either first or second in cumulative production over 3-month, 6-month, and 12-month periods in North Louisiana production. Initial rates are important to show productivity in the wells and to generate cash flow but it's also very important to perform over time and we subscribe to a truck management program whereby we generally limit daily drawdown of 10 to 30 pounds which we believe flattens the declines. We believe this data validates the quality of our acreage and optimum completion technique and maximizes cash flow generation, which is the number one driver in our corporate strategy. In general, there's a high correlation between longer laterals and higher profit concentration to EUR but we are more focused on the returns we are generating versus just EUR. As return on capital employed is critical to creating a very profitable and growing enterprise. Our economics as shown on Slides 24 through 26 show how exceptional this play is at current gas prices. We captured the early timeout performance on our wells, and when you combine that with high netbacks, very low LOE at less than $0.05 per Mcf and those severance tax until the earlier two years or pay out our returns not only compete or beat any natural gas basin, they compete with modes, most if not all, oil basins. Our business is a margin business where service costs are just as important as commodity prices, and when you bake in our hedges to the forward curve, at $2.75 to $3 gas, we can generate 41% to 61% IRRs on short laterals; 65% to 89% IRRs on 7,500-foot laterals; and 79% to 106% IRRs on long laterals. Again, we have girded our acreage and designed our drilling program to maximize returns, which are higher for longer laterals, but acreage configuration will also play into the ultimate development pattern. In summary, we are executing on all cylinders. Volumes are rapidly growing as evidenced by our results today and second quarter guidance. Our per unit cash operating cost will continue to fall, which will drive our margin expansion and provide for a potential doubling of our EBITDA in 2019 over 2018 factoring in current gas prices in our hedge book. The CapEx program for 2019 is extremely capital-efficient and designed to grow EBITDA dramatically while living within our means and keeping our debt metrics at very conservative levels. These trends are compelling, and even though we will not get out ahead of our Board on preliminary 2020 CapEx plans, if we were to hold our CapEx study in 2020, we would expect to generate significant free cash flow at reasonable gas prices. Whether you're an investor focused on value or growth, we check the boxes and look forward to delivering exceptional returns to our shareholders. With that, I'll turn it back to Gary for Q&A.

[Operator:]

We will now begin the question-and-answer session. [Operator Instructions] The first question is from John White with ROTH Capital Partners. Please go ahead.

[John White:]

Good morning, gentlemen.

[Walter Goodrich:]

Good morning, John.

[John White:]

Congratulations.

[Walter Goodrich:]

Thank you.

[Robert Barker:]

Thank you.

[John White:]

I don't think I've seen anybody beat annual guidance partway through the second quarter. I can't recall that happening on anybody I've covered before. But on your wells, the MSR Hunt 5H-1 that's a 4,600-foot lateral came in 17 million a day, and a well that you drilled a couple of quarters ago, the words about 35H number one has another 4,600 foot lateral that came in at 22 million a day. Is there - is it the higher profit loads on these - because these IPs are not that far under. Some of your 7,500-foot laterals, something about the geology where you drill the 4,600-foot wells that make them produce so good?

[Walter Goodrich:]

No. Not really, John. This is Gil. I think historically, if you look at our 4,600 over the last year or so, we probably have had slightly higher profit per foot levels, but I would say the difference between the Wurtsbaugh 35 and the MSR Hunt really is probably just a little bit more extreme choke management holding the rates back a little bit more. As Rob mentioned in his prepared remarks, we are seeing flatter curves and better results, which generally we're not quite as have initial IP or getting us more gas over the first three, six and nine-month period and therefore generating even better rates of return. So we're watching that very closely and making sure we don't pull them too hard initially and we probably get even a little bit more conservative over the last six months or so.

[Robert Barker:]

And John I might add on the Loftus wells, the 7,500-foot laterals. We would be very surprised if those wells don't outperform even our average on the 7,500 based on early time flow back. We've been very conservative on pulling those wells. Frankly, probably the flattest pressure profile that we've seen at an early stage. Those wells could produce a lot higher rates early time, but again, we're experimenting a little bit with an even more conservative choke program here to see if we don't outperform even the really good 7,500-foot performance today.

[John White:]

Well it sounds very positive. I appreciate the detail. Thank you.

[Robert Barker:]

Thanks, John.

[Walter Goodrich:]

Thank you.

[Operator:]

The next question comes from Welles Fitzpatrick with SunTrust. Please go ahead.

[Welles Fitzpatrick:]

Hey, good morning.

[Walter Goodrich:]

Good morning.

[Welles Fitzpatrick:]

Speaking about the Hunt, so it sounds like that - I mean on a per-foot basis, I guess that the short laterals always have a little bit more juice on a per-foot basis than the longer ones, but it was a touch lower than your other short laterals. It sounds like that's choke management and not the fact that it was just the first well that you guys have done in 13 north. I mean it's a little bit further south. Am I just reading too much into looking at the map here?

[Walter Goodrich:]

Yes. Welles, this is Gil. I would not read anything into the geology. We think it's all very, very similar rock. As I said, the Hunt did have a little bit less, slightly less proppant per foot from the [indiscernible] Wurtsbaugh 35 that John had mentioned. But it's really just choke management. I think that well is perfectly capable of drilling at a higher rate as we wanted to push it a little harder. And secondly, if you look at 4,600 versus 10,000, you know, 10,000 that comes on 30 million a day, we really are kind of drawing that reservoir down at a similar rate to a 30 million a day, 10,000-foot lateral something that's half that much call it, 15 to 17. So we think we're right in the right spot geologically. We think we're right in the right spot in terms of our methodology on flow back.

[Welles Fitzpatrick:]

Okay. Perfect. And on the A&D trends in the basin, it seems like the PE-backed companies are starting to focus a little bit more in the midstream side of their Haynesville ops versus the E&P side. Are you seeing more opportunities kind of get filled off and where you guys are thinking on that side of the business?

[Robert Barker:]

Yes. Welles, this is Rob. Certainly you are seeing quite a bit of emphasis from the private guys that we know talking about midstream spin off. You can obviously lay pipe, increase your throughput, create an income stream and then sell that off if you like. And as far as in our field, we have more flow lines facilities and many gathering lines versus taking that gas to a great distance away from the field. So it's always an option that you could carve that off and create more value that way by spinning it off. But as we sit here right now, that usually comes at a price. It depends on what you charge yourself and what cap rate you could then sell that at midstream off for. But you're typically left holding the bag a little bit on the working interest or the upstream side. So I think for us, we're just going to continue to do what we're doing, generate the value in the upstream side. And even though we own quite a bit of infield flow lines and gathering lines and facilities, I think we keep it all together.

[Welles Fitzpatrick:]

Okay. But do your competitors or compatriots in the basins, is they move in that direction, has that brought any acreage that might be of interest to you guys to market as they refocus on that side and you guys focus on…?

[Walter Goodrich:]

There's really no asset packages technically being marketed that we're aware off in the core of North Louisiana. You'd have to ask those guys whether they intend to divest if anything, but right now we're looking at everything we can to bolt on acreage to add to our inventory. We don't want to lever up to do it but if it makes sense, we're interested as long as it's in the right ZIP Code. So, really as you know, it's a small geographic area in North Louisiana where the core is dominated by 10 to 12 operators, and so far, we're not seeing anything other than small tracks that we've been able to replace our drilling inventory with over the last couple of years and we're going to continue to focus on that.

[Operator:]

The next question comes from David Beard with Coker & Palmer. Please go ahead.

[David Beard:]

Hey, good morning, gentlemen. Micro or macro question for you, just when you look at a micro level of this controlled flowback, we've seen this actually in oil basins where more people are using controlled flowback techniques, it seems to be producing better wells. When you look at your activities in Haynesville, we get to speculate to share some thoughts in terms of why controlled flowback seems to be producing higher total value wells?

[Walter Goodrich:]

Yes. So this is Gil. I'll take a stab at that question, David. In the Haynesville, in particular, I think it's a twofold combination of why the flowback is generating such strong results in the Haynesville. One is the Haynesville is abnormally pressured. So instead of 2.465 natural gradients, we've got something close to about 0.1 natural gradients. So we've got an extremely high reservoir with bottom hole pressure in excess of 10,000 pounds per square inch. And if you pull that too hard, that formation's pressure is going to tend to close up on it. So from the fracks that you've just been a bunch of money creating will have the heat upon themselves, which is the opposite of what we want to do. We want to keep them open and as much and long as possible. So maintaining as much pressure in the reservoir and a little drawdown at the near wellbore is clearly generating a better performance from the wells. Secondly, the Haynesville itself is a natural occurring porosity by law for almost 15%. To give you a benchmark, Cotton Valley across this area which historically has been pretty good conventional reservoirs in the range of 12% to 15%, and by core, we're looking at porosity in the 9% to 12% range. So it is a shale that's got an awful lot of course and a relatively small amount of clay in it which gives it a little more of a conventional type characteristic in my mind, and the combination of those two things means that if you'll just hold back a little bit on your choke and not try to pull it too hard, you'll both keep your top open in the quality of the matrix porosity itself can help continue to move gas through the reservoir.

[David Beard:]

Great, and appreciate all that details. And then just shifting to a bigger picture question on capital spending, you did a pretty good job saying you're comfortable with the budget, and I don't see a lot of reasons for you to blow up the budget or lift it, but I know that's been a concern with some people out there. Maybe just talk a little bit more about what you can't control on the budget this year and next year. And if it were to be higher, would it be really unanticipated working interest assumptions? Or might there be something else that's not in your control which would push spending higher?

[Robert Barker:]

Sure. David, this is Rob. First of all, we're not expecting it to be above our guidance range or we would've mentioned that. We're comfortable with where we sit right now. You can't always predict the future but we routinely grind on the model and where we're headed and we're comfortable that we're still deep in that range. We have seen a benefit of proposing wells and acquiring non-operated interest via farm out because non-operated working interest may or may not have the capital to participate, and so that can clearly add working interest, net revenue interest and incremental volumes to the wells that you originally didn't plan for but we do have the ultimate hedge is just to slow down. We're not into any long-term contracts on rigs. We can defer completions if we choose to do that for gas prices or budgeting purposes. We can move the rigs around if we choose to do that. Right now we're very comfortable where we are, the fact that we have such a significant portion of our projected volumes hedged above market price that's going to allow us to stay on budget we think and continue to hit the EBITDA projections that we've laid out. And I might just add which no one has asked yet but reviewed the new credit facility and the refinancing of our second lien notes this morning to be a very important and significant step forward, which allows us to do all the things that Rob just talked about. So barring some major changing commodity prices or some major changing in our cost structure which neither of which we're really anticipating, we don't see why we're not still in the 2019 plan.

[David Beard:]

Great. Appreciate. All the details gentlemen. Thank you.

[Walter Goodrich:]

Thanks David

[Operator:]

The next question comes from Joe Allman with Baird. Please go ahead.

[Joseph Allman:]

Thank you. Good morning, guys.

[Walter Goodrich:]

Good morning, Joseph.

[Joseph Allman:]

Hi, Gil or Rob, any plans to improve liquidity as it tightens a little bit as you redeem the 2 notes?

[Walter Goodrich:]

Yes. This is Gil. I'll take a stab at that. First and foremost, Joe, is we'll go through another borrowing base review here not too far down the road this summer and then we'll go through probably another one and we'll certainly go through another one in the fall, so in September October. As we continue to add these kinds of walls like we've just added, we expect the bias to be an upward movement on the borrowing base which would expand liquidity. We got some assets hanging around that are non-North Louisiana core that we could potentially sell down and/or sell out completely which would further boost liquidity. And as Rob said, we could always just slowdown and certainly slowing down would be a form of losing liquidity because we had more cash flow that would allow for us to paydown debt. So I think we got a lot of areas in the quiver and we're very comfortable with where we are.

[Joseph Allman:]

Okay. Very helpful, Gil. Thanks for that.

[Operator:]

The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

[Jeffrey Campbell:]

Good morning, and congratulations on the strong quarter.

[Walter Goodrich:]

Thank you, Jeff.

[Jeffrey Campbell:]

I just want to ask you, earlier today, Chesapeake indicated that it's slowing down in the Haynesville and it's going to go from 2 rigs to 1 by the end of 2019. I just wondered if this would have a specific effect on your capital spend in activity level. And if it did, would you shift dollars to operating locations as a result?

[Robert Barker:]

Yes. Jeff, this is Rob. Really the vast majority of our capital this year is already operated. I think there's potentially 3 gross very small net working interest wells or small net working interest wells that we could participate in at a later date. That's all that's on the schedule. So it really is not going to shift a whole lot of our capital back to operated versus what we currently planned for. We remain interested in trying to swap acreage with them. We think it's a positive development for both companies if that were to take place, but we have no specific plans currently for that. And we have noted that they're reducing their rig count. Obviously, I think most of their acreage, if not all, is held by production. So that's obviously a thing that they can do. I might just differentiate a little bit. If you're looking at our operated activity, as we've always said, our gathering fees are lower. Our rates of return are higher than some of the operators, other operators in the play, and so it all depends on comparatively what plays they have to generate better rates of return. But for us, it's not - it doesn't appear that it's going to affect our budgeting much, if any.

[Walter Goodrich:]

And then one last comment for me. As a reminder to everybody, in our joint venture with Chesapeake, we do retain the option of proposing wells to them, so the fact that they want to slow down or quick entirely doesn't impede us from having joint development.

[Jeffrey Campbell:]

That was really thorough collar. I appreciate that. And just kind of stepping back, listening to the call, I mean thinking about what we just discussed with Chesapeake and then the earlier discussion with Welles about midstream activity and so forth. I'm just wondering, and also you've stated in your summary and outlook that strategic acquisitions that add accretive inventory is something that you're always on the lookout for? I was just wondering if other people - if the will of the wind seems to be to reducing activity, would this give you a chance maybe to make acquisitions in terms of either increasing working interests through - concerns like you already alluded to. Or there might be the possibility to pick up some acreage and some locations, maybe small bolt-ons, but high quality core acreage.

[Robert Barker:]

Sure, Jeff. We're very interested in that. Again, as we've said, what we don't need to do is lever up to do it, but bringing the drilling rig, farming in opportunities, combining blocks, swapping acreage, all of that is of interest to us. We don't want to diminish down the inventory by moving too far out of the core. But there's certainly acreage and what we call the Shelby Trough or Angelina River Trend that could potentially also come into the inventory if we found the right deal. But again, what we don't want to do is, is lever up to buy something then put it in the back of the inventory when in reality we have 10 years and over a TCF of reserve exposure already ring fenced in our inventory.

[Jeffrey Campbell:]

Yes. Well that makes perfect sense. And the last question I wanted to ask you, it sounds like that you've indicated that these recent wells that we've been talking about this morning are outperforming your expectations. I was just wondering, does this increase the likelihood that your full-year 2019 production is going to land more towards the upper end of guidance as a result of these wells?

[Walter Goodrich:]

This is Gil. Conceptually, yes. But I don't think we're ready to go make that kind of a bold prediction. We're happy with the guidance. So we have had a trending of tighter and tighter interval spacing per well, and we think that certainly is a contributing factor to the recent performance.

[Jeffrey Campbell:]

Okay, great. Thanks. Again, congratulations on the quarter.

[Robert Barker:]

Thanks, Jeff.

[Operator:]

The next question comes from David Snow with Energy Equities. Please go ahead.

[David Snow:]

Yes. Hi. I'm wondering when you call the existing convertible second lien notes, how will that affect the fully diluted share count? You have a potential of shares above the market and can you walk us through what that would do to fully…

[Walter Goodrich:]

Sure. David, this is Gil. Those convertible shares will go away and come out of the fully diluted share count, that's number one. And then the reissue of the 12 million would have its pro rata share of those shares would continue to stay out there. So what's that math?

[Robert Barker:]

Yes. So David, this is Rob. So there's 1.875 million shares associated with the $40 million of principle and the existing notes converted at 21.33. If you just replace another $12 million that would be basically 30%. Yes, 30% of that number would put back on because the new notes do convert at the same conversion price of 21.33.

[David Snow:]

I didn't know they were convertible. Okay. So it reduces it by 70%.

[Robert Barker:]

70%. Yes, 1.320 million shares.

[David Snow:]

Yes, 320.

[Robert Barker:]

1.320 million shares.

[David Snow:]

Okay. I'm wondering given all the pipelines coming on to the Gulf Coast from the Permian natural gas in the second half, do you have any indication in - from futures and markets are just generally talking of what the outlook is for the unhedged gas market out there versus right now?

[Walter Goodrich:]

Well, no insider intel in the future, Dave, rather than what we're seeing from NYMEX, which is roughly tied to Henry Hub pricing. So internally we're kind of the camp that is going to be a good thing and a positive thing with the incremental LNG coming on the second half this year. To what extent that really moves the needle? We don't know. We'd say the market today is a little bit on the bearish side from where we really think prices should be with the selloff we've seen in the last 90 days or so. But as we've said, our business is to protect our capital and our hedge position we think does that.

[David Snow:]

Okay, all right. Thank you very much.

[Walter Goodrich:]

Thanks David.

[Operator:]

[Operator Instructions] The next question comes from Rehan Rashid with B. Riley FBR. Please go ahead.

[Rehan Rashid:]

Good morning. Just two quick ones. One, what gas price would make you slow down? And then second, on a completion - on a well cost basis, kind of any kind of color on the current market? Are we seeing some inflation? Or could you see some kind of better completion methodology that would lower costs as well?

[Walter Goodrich:]

I'll take the first part, Rehan and let Rob handle the second part. We don't have a specific hard-line price. Obviously, it's all about the margin and so it's a relationship to the price to what our overall costs are - which is the second part of your question. But we would say, look I mean - and then we had to layer in our hedge position both in the amount and the tenor and the price of those hedges, but we're very comfortable with where we sit today in terms of we've got nice hedges all the way through the first quarter of 2020. But I will tell you if we start getting materially below $2.50 gas price, particularly when the strips would be at that or lower price over a longer period of time. We would probably be starting to have a bias towards a slowdown rather than continue our rates. So I'd say a call it down around $2.25 or, so we clearly would be wanting to slow down our activity. But again, we don't have a hard and fast line drawn in the sand.

[Robert Barker:]

And just to add to that, Rehan, you look at our hedge schedule. We're basically 70% of midpoint of guidance hedged at $2.89. Our average lateral length this year closed to 7,000 feet. So if you look at our 7,500 foot laterals, even at $2.50, they generate 45% IRRs, but we're going to realize a lot higher than that because 70% of our gas is hedged at $2.89. So we really think even in a $2.50 environment, you're really looking at a $2.75 economic here on an average 7,500-foot lateral, which would have you generating 65% IRRs. So hard to imagine us slowing down dramatically, but as we said earlier, that is our ultimate hedge. If we choose to be more conservative, the gas prices aren't cooperating.

[Walter Goodrich:]

And so on the second part of your question, what you're seeing - actually looking at the overall U.S. land-based rig count and its direction of late and he mentioned a minute ago and on one of the questions about Chesapeake slowing down. We're seeing probably what we would call slightly deflationary environment in the Haynesville today, certainly no inflation and we'll just see how that plays out, but it's clearly going to be driven by both overall activity because obviously a rig and a frac crew is agnostic as to whether it's completing - drilling and completing an oil well or gas well. So there is a bit of a relationship between the oil price and the gas price but we've seen fairly stable to slightly improving prices over the last nine to 12 months.

[Rehan Rashid:]

Okay, thank you.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Gil Goodrich for any closing remarks.

[Walter Goodrich:]

Thank you, everybody. We appreciate you spending the time to listen to us this morning and follow the company, and we look forward to reporting second quarter results to you later this summer. Thank you.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.