Goodrich Petroleum Corporation
Q1 2018 Earnings Call Transcript

Published: 15 May 2018

[Operator:]

Good day and welcome to the Goodrich Petroleum First Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there'll be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.

[Gil Goodrich:]

Thank you, Alice, and good morning, everyone. Thank you for joining us this morning, and we are pleased to have an opportunity to share our first quarter results with you as well as provide an update on our recent activity. We prepared a slide presentation in conjunction with the call this morning. And we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on our website entitled Earnings Call Slides First Quarter 2018. Our standard disclaimer, forward-looking statements and risk factors are highlighted for you on slide two. I will begin with slide three where we provide you a quick overview of the company including our assets, which are located in Haynesville, Eagle Ford and Tuscaloosa Marine Shale plays with our focused on the Haynesville Shale where we have a 10 to 15 year inventory of development locations and approximately 1.2 Tcf of reserve potential. Our company’s common stock is traded under the symbol GDP on the NYSE American and we have seen of late a gradual increase in both the float and liquidity. Our plans and catalyst for 2018, called for rapidly growing production and EBIDTA while also keeping our debt metrics at very conservative levels. All of our growth will come from the Haynesville Shale where we recently added two non-operated wells with average lateral length of approximately 9,700 feet, and average initial rates for each well of approximately 35 million cubic feet of gas per day. This morning we also announced an agreement to sale a small portion of our western most TMS wells and associated acreage for $3.3 million. When couple with a $23 million East Texas sale we announced in March the sales increased our liquidity and drive for the acceleration of our core Haynesville Shale assets. In addition, we have recently reached an agreement on an additional swap of acreage in the core of Haynesville, which will further increase our inventory of operated long lateral Haynesville wells. Due to unanticipated delays of almost two months fracking our Cason-Dickson 1H and 2H wells we are revising our full year average production guidance to a range of 65 million to 75 million cubic feet of gas equivalent per day, while maintaining our projected 2018 exit rate of approximately 100 million cubic feet of gas equivalent per day. It is probably worth noting the adjustment of the full year production guidance is solely a calendar year timing issue and not a result to any change in well performance or forecast. While we reiterate our preliminary 2019 production guidance of 140 million to 154 million cubic feet of gas equivalent per day, due to the adjusted timing of the delayed wells, we are increasing our 2018 production growth guidance to 100% to 120% over the midpoint of the 2018 guidance. If you'll now turn to slide four, I will review some quarterly highlights and recent developments. During the first quarter, we incurred capital expenditures of $21 million, which is considerably below of what we anticipated spending due to delays incurred in completing the Cason-Dickson wells. However, we are increasing our anticipated second quarter capital expenditure accordingly and provide guidance this morning of approximately $30 million for Q2 CapEx. Our updated capital expenditure budget for 2018 will be 100% focused on the core of the Haynesville Shale, where we now expect to drill 17 gross and 8 net Haynesville wells with an average lateral length of approximately 8,000 feet. We are also reaffirming our full year CapEx guidance of $85 million to $95 million. For 2019, our preliminary CapEx plans remain unchanged with a range of $125 million to $150 million, which we project will more than double production and EBITDA over our 2018 guidance. For the first quarter we came in below our prior expectations at an average of 37 million cubic feet of gas equivalent per day or 30.3 Bcfe for the quarter. The lower reported production was due to the shut-in production of approximately 4.3 million cubic feet of gas equivalent per day, while conducting offset frac operations and the aforementioned delay in fracking the Cason-Dickson 1H and 2H wells. As described in our press release this morning, the primary reason for the delay in fracking these wells was a downhole equipment malfunction in the Cason-Dickson 2H well, which obstructed a portion of the lateral and resulted in a reduced lateral completion. We've adjusted all future well plans to eliminate this particular malfunction from occurring. In addition, the wells have now been successfully frac stimulated and we expect both wells to be on flowback later today. While we'd hope to be ready to report initial production results from these two wells to you this morning, we will provide initial results after both wells have reached peak rates in the next couple of weeks. The shut-in production has been restored and as previously mentioned we have recently added two non-op Haynesville wells to production. As a result, thus far in the second quarter, we have averaged approximately 47 million cubic feet of gas equivalent per day and we will be adding the two high working Cason-Dickson wells to production shortly, which we expect will increase net daily production in access of 70 million cubic feet of gas per day. During the first quarter, we reported adjusted EBITDA of $3.4 million again, which was impacted by the previously mentioned shut-in of production and completion delays. However, with the addition of the Cason-Dickson wells and the upcoming drilling and completion schedule, we continue to project robust cash flow and EBITDA world in the coming quarters and in to 2019. Turning to slide five, you'll again see the chart showing our year-end 2017 SEC proved reserves and the reserve growth over the last couple of years. Proved reserves grew last year by over 40% compared to year-end 2016 to 428 bcf equivalent. Consistent with our focus and development activities all of the reserve growth were associated with our core Haynesville Shale assets. On slide six, you will see our current capitalization table. During the first quarter and following the East Texas asset sale, we paid off all outstanding amounts under our senior credit facility and ended the quarter with $9.7 million of cash and nothing drawn on the RBL. As a result the balance sheet remains in excellent condition, with only the second lien convertible notes outstanding and net debt of just $39 million at the end of the quarter. Given the aforementioned well delays we also delayed the April RBL borrowing base redetermination so as to include the recently completed wells. And we expect to have higher borrowing base upon redetermination and prior to the mid-year review. Slide seven illustrates the robust production growth we’re anticipating for the second quarter through the end of the year. As I mentioned earlier we revised our production guidance to accommodate the completion delays where we now expect full year production to average about 70 million cubic feet of gas equivalent per day at the mid-point while maintaining our exit rate forecast of approximately 100 million cubic feet of gas equivalent per day. And with that, I’ll turn the call over to Rob Turnham.

[Rob Turnham:]

Thanks, Gil. Looking at the first quarter our revenues were $11.8 million from an average realized price of approximately $3.57 per Mcf equivalent. That was comprised of 2.68 per Mcf and $65 oil. When factoring in our hedges natural gas prices averaged $2.69 and oil price averaged $57.99 per barrel, 67% of our revenue was attributed to natural gas production in the quarter. Moving to operating expenses, LOE was $2.6 million or $0.77 per Mcf equivalent for the quarter versus $4.3 million or $1.86 per Mcf equivalent in the prior year period and $2.7 million or $0.93 per Mcf equivalent in the prior quarter. LOE for the quarter included $300,000 for workovers. Production and other taxes totaled $600,000 or $0.19 per Mcf equivalent in the quarter versus $700,000 or $0.28 per Mcf equivalent in the prior year period. As a reminder Haynesville wells drilled in North Louisiana have severance tax abatement until the earlier payout of two years and therefore the company’s production and other taxes per unit of production is expected to remain low in the near-term as new Haynesville wells are added. Transportation and processing expense was $1.3 million or $0.40 per Mcf equivalent in the quarter versus $1.6 million in the prior quarter. As we have higher percentage of operating activity our transportation and processing expense will trend lower as we develop our inventory. DD&A expense was $3.5 million in the quarter versus $3.2 million in the prior quarter, which had similar rates of approximately $1 per Mcf equivalent. General and administrative expense was $5.2 million in the quarter, which includes non-cash expense of $1.7 million for stock-based compensation. G&A payable in cash for the quarter was $3.5 million. We had an operating loss in the quarter of $1.3 million versus an operating loss of $1.2 million in the prior quarter. Interest expense totaled $2.7 million in the quarter, which includes cash interest of $200,000 incurred in the company's revolver which occurred prior to pay-off during the quarter and non-cash interest of $2.5 million incurred on the company's convertible notes, which is comprised of $1.6 million of paid in-kind interest and $900,000 of amortization of debt discount. Moving back to our slide deck, we’ve included several slides beginning with slide eight that show how we trade relative to an approximate 50 company peer group. Even though we’ve had a nice run since May 9 when this analysis was run whether it is 2018 enterprise value to consensus EBITDA, net debt-to-EBITDA, growth in EBITDA per million of capital expenditures or capital efficiency, which bring very key relative to our peers. We continue to believe that we will trade better overtime as volumes and cash flow grow throughout the year. Slides 12 and 13 show our updated property slides, which reflect our 22,000 net acre position in the Haynesville, 65,000 net acre position in the TMS and 14,000 net acre position in the Eagle Ford. We have an average working interest of approximately 40% on our core North Louisiana acreage, with over 200 gross 95 net potential locations in inventory. Approximately half of the locations are capable of 10,000 foot laterals currently, with the remaining half split between 4,600 and 7,500 foot laterals. We had gritted out 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. We estimate, as Gil said earlier approximately 1.2 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone, of which we operate approximately 55%. Not much has changed on our recent industry activity map on slide 14, although industry activity remains high with approximately 50 rigs running in the play. We continue to show an abundance of well results on our decline curve analysis slides, beginning on slides 15 and 16. With 59, 4,600 foot laterals with average profit of 3,300 pounds per foot and as much as two years on a handful of wells. The composite production curve is generally following our 2.5 Bcf per 1,000-foot type curve as shown in red and our Wurtsbaugh 26 well, which was frac with 5,000 pounds per foot is performing well above the curve. Moving to slide 17 and 18, which reflect our two 7,500 foot curves. We continue to show 87 wells with an average propane concentration of 2,800 pounds per foot in our product curve, 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 propane concentrations flow through overtime. Slides 19 and 20, which show composite results from 35 approximate 10,000 foot laterals, with an average of 3200 pounds per foot of profit, we are also tracking our 2.5 Bcf per 1,000-foot type curves. In general longer laterals typically make better wells, although we are focused on IRR not EUR, as returns matter more than ultimately recovery of reserves. Our current 2018 capital expenditure budget contemplates an average of approximately 8,000 feet of lateral. Our economics as shown on slides 21, through 23, show how exceptional this play is at current gas prices. At $2.75 to $3 gas, we can generate a minimum of 36% internal lateral return for our 4600 foot lateral at $2.75 gas to as much as 76% at $3 gas for a 10,000 foot lateral. All with a blended average gathering rate and basis of $0.60 per Mcf equivalent. With the amendment to our gathering rate on a portion of our acreage and the higher operated percentage of our activity over the next couple of years, we expect to see further reduction in transportation charges overtime and higher rates of return as our operated gathering fees average $0.22 to $0.37 per Mcf dependant on the area. The superior economics are driven by varied productive rock, high realized prices being $0.12 to $0.15 off of Henry hub, low LOE, an average of about $0.05 per Mcf equivalent and even lower in the initial months. And no severance tax until the earlier of two years or payout. We have wells currently that have paid out in less than a year. In summary, our capital efficiency and full-cycle returns in the Haynesville are robust, regardless of the commodity and you will see meaningful growth of volumes, a continuing expansion of our cash margin and significant growth in EBITDA in 2018 and beyond. We believe we can deliver this dramatic growth in EBITDA, while maintaining a debt level at less than 1.5 turns. With that, I’ll turn it back to the operator for Q&A.

[Operator:]

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question will come from Neal Dingmann of SunTrust. Please go ahead.

[Neal Dingmann:]

Good morning, gentlemen. Rob -- my first question for you, Gil Just on the frac side, I know you had some sort of structural issues. When I look right now, you talk about number one, frac availability as you periodically going to need that down the line that part of the backlog. And then number two, just from an offset as you have to shut-in wells, you mentioned that I know a little bit in the press release, I'm just wondering going forward how much of that we’ll see?

[Gil Goodrich:]

Yes, good morning, Neal, this is Gil. Good question. So I take the first part of the first, frac availability in the Haynesville was actually improved a good bit over the last six months or so primarily due to increased capacity several of the large frac providers have added to their local yards and have more cruise in play. We have plans for another well to be frac next month and then another one in early August, I think in the next two in the queue after these that we just finished up. And right now it looks like we're on schedule with those dates. So we’re not anticipating any further vendor related delays if you will for the rest of this year. That could always change, but currently it looks like we're in pretty good shape for the remainder of the year schedule. As to the offset frac, it really is a very location specific question, Neal. It's very important that if there is an offset well, be at an old parent well or a new well if you shut those wells in during the frac operations. Because you want those wells to be charged up with pressure, while you're conducting frac operations otherwise you'll have a risk of moving too much fluid out into that crossover area. So the good news for us is as we look forward to the balance of this year, the majority of what we're going to be doing is not going to have much if any offset well necessity to shut-in and those that will would be older low volume parent wells. So we're not expecting the kind of delays from frac operations or shut-in in the coming quarters.

[Neal Dingmann:]

Very good. And then just one follow-up for either one of you. Starting on slide 15, could you just talk about the declines in these wells continue to -- IP is obviously continue to look very strong. But it looks like to me the decline now these days versus years back when we had them look much different. If you could just address those starting on 15 and how you sort of foresee going forward? Thanks.

[Rob Turnham:]

Sure, Neal, this is Rob. Well what's made the play, what's caused the renaissance is obviously better, stimulation tighter frac intervals, higher propane concentrations and higher recovery of the gas that's in place. That combined with choking your wells back early time and monitoring the pressure draw down has flattened the curves a bit. Where you see -- in fact you see it really a great example of that on slide 15 our Wurtsbaugh 26 well where we bring the well online, we choke it back we keep the pressure drawdown to about 30 pounds per day of less pressure. And the curve is outperforming our type curve. And so back in 2008 to 2014 when we were pumping 1,000 or 1,100 pounds per foot over a wider frac interval we just weren't getting good near wellbore stimulation and therefore the wells fell off harder. And so that's part of what we think the better stimulation not only higher initial rate the flatter curves if you manage your choke better. Now the wells that start to fall off of our curve on slides 15 through 17 or 15 through 19 all the wells that were under stimulated that had wider frac interval. So when we first got started and another operators were probably on average pumping a frac interval at 200 to 225 feet per stage, we believed and are reducing our intervals to 100 to 150 feet per stage. And we think that along with the higher propane concentration is flattening the curve and basically capturing a higher percentage of the gas that's in place in your wellbore.

[Neal Dingmann:]

Very good. Thanks guys.

[Rob Turnham:]

Thanks, Neal.

[Operator:]

Our next question will come from Phillips Johnston of Capital One. Please go ahead.

[Phillips Johnston:]

Hey, guys thanks.

[Gil Goodrich:]

Hey, Phillips.

[Phillips Johnston:]

Hi. On the amended gas gathering agreement can you summarize what the trade-off was in exchange for the lower rate? I assume the term was extended out a number of years are there any details that you guys can provide?

[Rob Turnham:]

Yes, Philips, again this is Rob. Really the driver was activity, the midstream provider was noticing all of our operated activity adjacent to them. They want to see activity on them and needed to get more competitive with what we have on our other operated acreage. And so it really was a driver of -- we’re willing to reduce these fees as long as we see an activity level pick up on that block. So we already had a dedication to them on our take in kind non-operated volumes. So was no -- there was a little extension of time to that, but basically not material on our mind. It was really just a commitment on our part to get those reduced rates was just dragging a rig on and increasing the activity level. And again the genesis around that was the fact that we had the swap that was going to open up additional operated long laterals for us that we could then drill the wells, bring them online and get the reduced gathering feed by virtue of completing those wells.

[Phillips Johnston:]

Okay, sounds good. And then just a follow-up on Neal’s question on frac availability. I think you guys recently talked about pressure pumping cost kind of running around $80,000 per stage as of a couple of months ago at least, which I think was down from around $115,000 or so around a year or so ago. Has the leading edge pricing moved much off of that $80,000 per stage number?

[Gil Goodrich:]

Yes, Philip, this is Gil. So it really is a function of exactly what your design is and how much proppant and what type of proppant you’re pumping. The wells we just finished were actually slightly cheaper than that little less than 80,000 a stage, but that was mainly driven by just design. So I think that we’ve not really seen any appreciable change in overall rate structure in the last three months or so.

[Phillips Johnston:]

Okay, sounds good. Thank you, guys.

[Gil Goodrich:]

Thanks.

[Operator:]

Our next question will come from Mike Kelley of Seaport Global. Please go ahead.

[Mike Kelley:]

Hey, guys. Good morning.

[Gil Goodrich:]

Good morning, Mike.

[Mike Kelley:]

On the swap front really just kind of seems like win on two fronts here, you added to your inventory 10,000 foot laterals and then you had this decreased gathering cost ironed out too. Just curious if you see more opportunities like this if you kind of give us a sense of how can an A&D and acreage swap environment looks in the basin right now? Thanks.

[Rob Turnham:]

Yes, Mike, this is Rob again, yes we’re clearly working that angle. We see real benefits to both operators on a swap other operators are receptive to that idea instead of drilling shorter laterals it make sense to swap acreage, so that we can both maximize our plans. And we’re continuing to work bigger blocks as well, but as you know it’s a fairly small geographic area dominated by 15 operators, many of whom are bigger. Some of those blocks have higher gathering fees or minimum volume commitments that would dilute down our margin a bit. So we have to be careful not to work our way into something that that kind of takes our average economics down. But we continue to work some of the smaller transactions and bolt-on opportunities because we see real benefit to kind of leveraging into that, in particular if we can do so by virtue of kind of drilling our way into the block. So for example this next well that we’re actually currently drilling even though it’s a shorter lateral it earns us additional acreage. And so more opportunities like that where you can carry someone for a small interest that equates to a much lower price per acre than what it would take to buy them out, and they get to stay in for some piece. That’s the structure that we really like and we think is beneficial to continue to pursue.

[Mike Kelley:]

Makes sense, that’s great. And then maybe on the flip side of that, would love to get maybe an updated thought on strategy or plans for the TMS and the Eagle Ford site. You have a small sale on the TMS. Things like -- seems like activity is kind of heating up for the Austin Chalk play there. Just would love to hear your thoughts on all that’s going on around that. Thanks.

[Gil Goodrich:]

Sure, Mike, this is Gil. So I take the first one which is quite simple the Eagle Ford, we've got about a 14,000 acre kind of legacy position. We believe this is a tier 2 position in the overall Eagle Ford play. I think our plan is we would be receptive to proposals to take us out of that. We've had some conversations along those lines nothing definitive to talk about this morning, but I think that's something that’s pretty high on the non-core divestiture list for the company. Moving over to the TMS, we have been watching quite closely what's going on with the Lusitania Austin Chalk, no question that the small divestiture we announced this morning is related to that play. So we're pretty happy given our position to kind of see how that Lusitania Chalk plays out obviously very early innings with only really one well that's been drilled and fracked, frac stimulated. We continue to like our TMS position, we got about 65,000 acres there, particularly what we like on the South Eastern corner, which comes into Louisiana tangible Parish area where we've got some wells that we've drilled early late in the pre-clash timeframe that I think performed extremely well. But look, the challenge for us is with the rates of return that Rob identified in the Haynesville, where do we have to get to, to be able to kind of match those rates of return. And I think right now we got about 35,000 to 40,000 acres that's held by production I think we're pretty happy to just kind of sit and hold that and see how this old rally plays out as well as what's going on around this in the Lusitania Austin Chalk.

[Mike Kelley:]

Okay, great. And I didn't asked a second question, he just texted me and said I could ask it for him. I’ll take one more, by 2019 it looks like still rushed out production growth in the works here and we're just seem like you're on the break of kind of breaking out the production side in general going from 37 in Q1, 37 million a day the exit rate of $100 million. Maybe could you talk about that trajectory in 2019 a little bit. I'm kind of curious how you see the potential exit rate in 2019? And then if you can refresh us on what the gross and net wells sounds for you embedded in that CapEx number of $125 million to $150 million? Thanks.

[Rob Turnham:]

Yes, sure Mike. And obviously we've built in some risking relative to our growth guidance for 2019 and particularly it's awfully far away. And as we've seen here potential things can happen that really upset the cart. I will tell you and I had some conversations earlier with some others that obviously as the base grows, one well result has less impact on the variability of results. What we have right now is we have a company that starting from a low base and adding meaningful volumes from individual wells that give you a hockey stick growth profile. And as we get bigger that's going to smooth out a good bit. But certainly if you take the risking off of our 2019 guidance and you do what we think we're going to potentially do instead of existing 2018 at $100 million a day you could see us exit 2019 at $200 million a day equivalent. And obviously that get you to in excess of 100% growth even exit to exit after hitting a pretty high rate in fourth quarter of 2018. The sequence of that growth is going to be a little more stair step than what we have in 2018. So kind of a more gradual growth from the exit to growth of the exit in Q1 of 2019 and then further growth throughout. We've not given a gross and net cadence yet on completions for 2019. We have included the 2018 cadence on completions in the appendix of our slide deck. And I would encourage the listeners to kind of look at that that will help model when these wells are expected to come on through 2018. And one more point to mention here, we talk about living within our debt metrics. We think obviously EBITDA is going to more than double in 2019 versus 2018 if you [plug in straight] pricing and yet we keep our debt metrics well below the one and half turn targets. So we are not going just level up to get the growth we have been there and done that. And so concentration on debt metrics, while growing production and cash flow dramatically and minimizing the outspend yet providing significant value to the shareholders is priority one.

[Mike Kelley:]

Got it, appreciate the detail.

[Rob Turnham:]

Thanks, Mike. Thank you.

[Operator:]

Our next question will come from Ron Mills of Johnson Rice. Please go ahead.

[Ron Mills:]

Good morning guys. As it relates to the last comments Rob, when I look at your cadence and just gross and net wells, it look like you are shifting more activity to Thorn Lake away from Bethany-Longstreet and it looks like that’s driving an increased average working interest for the year, just curious in terms of the background behind that shift and how that might look as we look to model 2019 as well?

[Gil Goodrich:]

Yes, Ron, this is Gil, I will take at least the first part of that and then Rob can chime in. So the Thorn Lake area, we added some acreage last year and part of that as Rob described earlier was an earn in. So we are drilling some wells that are fully earning that acreage. So we’ve got a timeline that we have to adhere to there. So we drilled the first couple of wells and we got a couple of more we want drill before the end of this year. So that’s really what’s driving that on one hand on the other, if you look historically at that area while the Haynesville was a little bit thinner it actually is one of the very best parts of the play in our EURs from parent legacy wells is actually a good bit higher or fair amount higher I should say than even in the core of the Caddo and DeSoto Parish area. So we really like the area, we think this is extremely good area and we are earning additional acreage so all that make sense.

[Ron Mills:]

Okay.

[Rob Turnham:]

Ron, I will jump in one last time. So really we have six wells that we need to drill via this farm out that we took. And so we’ve basically drilled two of the six and as Gil said two additional ones this year. And so you could -- if you look out into 2019 you’d have another two wells that we would drill during 2019 to fully earn that acreage.

[Ron Mills:]

Okay, great. And when I look at the industry activity slide couple of things, one common stock side some pretty good success up in Caddo Parish I don’t think you’ve had -- you have done very much in kind of your Greenwood-Waskom Metcalf areas, but any commentaries on your acreage position given those recent results with the latest completion vintage?

[Rob Turnham:]

Yes, this Rob again. We like what we see and we are not surprised by it if you look at the old vintage Greenwood-Waskom wells that we drilled they were pretty close to being as good as Bethany-Longstreet. I think we have always kind of said if you are going to put a percentage on it call it 85%, 90% as good as what we see in Bethany-Longstreet. So, yes, congrats to common stock, but we are surprised that they made very good wells there. I think towards the tail end of 2019 you could see us drill a well or two there, but we have revised our schedule in particular to include the swap acreage and we are just not going get up there, we don’t have current plans to get up there before then.

[Ron Mills:]

Great. And just curious in terms of on that 2H well at Cason-Dickson the equipment failure that happen was it -- what in the design are you changing where you’re saying that will no longer be a risk?

[Gil Goodrich:]

Its Gil, and I have triggered you to ask that question, let me give you simple and concise of an answer as possible it’s getting down into the engineering weeds a bit, but one of the challenges with the long laterals is that you are getting out to measure depth of 21,000 to 22,000 feet of measured depth when you get out of 10,000 feet lateral. And quarter two being generally start to see friction lock due to the long length somewhere around 18,000, 19,000 feet occasionally we can get out longer than that, but in many cases you can’t -- you just got too much friction that far out and the problem with that is we need to have a conduit into the formation so that we can pressure up and get communication with the formation and be able to pump down the perforating guns for stage one frac. This has been a bit of a challenge, from what we saw about a year and half ago, the industry was going through running something called post sleeves, which are ports on the end of the very furthest out join of casing and by design you can pressure up on those ports open them, pressure up breakdown the formation and create your conduit, you need about 10 barrels per minute of flow to drop your guns in and run those guns down into place to perforate stage one. All of the wells that we participate in from a non-op standpoint, all the wells I should say till here very recently all the wells that we drilled last year and this year including the Cason-Dickson 1, we have run the post sleeves and had no problems or issues. On the Cason-Dickson 2, for some reason the ports would not open and what it appears is that a wiper plug going down cross over that slightly smaller ID or interior diameter of the casing, which cause a malfunction of the wiper plug, which cause some degree to come back up the whole, which led to the problem. So that’s behind us, moving forward we will not be running toe sleeves again, that’s for sure, and we will go in, if we can’t get down the cold tubing we’ll put a rig on it and go down and perforate stage one with stick pipe and create the conduit, once you have done that, then you are up and running and you have no more issues. So anyway, it’s concise back and make it that was the issue and what we will do going forward as we won’t toe sleeves, which is obviously the problem that created the problem here in the first place.

[Ron Mills:]

Okay. And is it fair to assume that the changes in the way that you drill and complete the wells in terms of the economics and the well costs that didn’t have any impact on the well costs, given…

[Gil Goodrich:]

Yes, di mimimus change in well costs, Ron.

[Ron Mills:]

Great, alright. Thank you, guys.

[Gil Goodrich:]

Thanks, Ron.

[Operator:]

Our next question will come from John White of Roth Capital. Please go ahead.

[John White:]

Good morning gentlemen. And my questions were answered, but congratulations on your new gas gathering deal, it sounds positive.

[Gil Goodrich:]

Yes, thank you John. Really when you model the inventory with as much as $0.40, $0.50 reduction depending on who operates and what our volumes are, it’s extremely material value creator for the company. So we are excited about it and overtime you’ll see that flow through the financials.

[John White:]

Thank you.

[Gil Goodrich:]

Thanks, John.

[Operator:]

Our next question will come from Joe Allman of Baird. Please go ahead.

[Joe Allman:]

Thank you, good morning everybody.

[Gil Goodrich:]

Good morning, Joe.

[Joe Allman:]

In terms of your new guidance for 17 gross wells and 8 net wells. I am assuming that the 17 gross includes non-op wells and out of the 17 how many non-op well are you expecting for the full year?

[Rob Turnham:]

Yes, that is -- your assumption is right. That 17 includes the operate -- I’ll tell you we’re participating with Covey Park all four wells. Our interest is about 10% in each of those wells, they are drilling them off of the same pad. So gosh they spud back in the fourth quarter in December, and we are not expecting those to come online for quite some time. In fact I think October and you combine that with the Chesapeake activity, we’re really looking at 8 gross of the 17 gross wells being non-op, but when you look at the net well count then you’ll see, when you baking our high working interest on the operated wells, I think you’ll see north of 75% to 80% -- I think it’s north of 80% of the net well count is operated. So again it’s an example of an area that actually would get swaps on Covey Park, but we chose to participate and they’ve making obviously some very good wells. And we expect that production probably the start of the fourth quarter.

[Joe Allman:]

And year-to-date, have you brought online only two non-operated wells or it’s been more than that?

[Rob Turnham:]

Yes, it’s the two wells that we just reported in this release that’s been there. So really the well count has been very low as far as wells that had IPs in 2018 it’s really the three operated wells and the two non-operated wells today have taken the production where it is. And then we’ll get some momentum here throughout the rest of the year to get to our exit rate.

[Joe Allman:]

That’s helpful. And then different topic, when you model in frac delays in your own internal model, how many days do you put in your model for frac delays?

[Rob Turnham:]

Yes, I mean what we do is try to take a couple of weeks off the date that we’ve been given. We’ve had a little less I would say the delays that we’ve incurred have been a little less on a date that they show up. It’s just the fracs in the first quarter took longer due to pump problems. And so whereas we anticipated shutting in the offset wells and getting the first quarter wells frac and online basically was twice as long as what we had thought. So I think going forward that’s probably where you just have to bake in a little extra cushion, it’s not just on when they show up and how long it’s going to take for them to get the wells frac.

[Joe Allman:]

Okay, that’s helpful. And lastly one of the things it was lower in the first quarter versus our model was the -- your pre-hedge realized gas price. And so any insights into why that moved lower than the prior quarters and could you just talk about what are you expecting for that price going forward?

[Rob Turnham:]

Yes, so we’re doing some additional research on that, but we typically sell about 50% of our gas 1st of month and 50% gas daily. We’re trying to minimize the swing on whether one works better than the other. Clearly had a little bit wider differential than what we’ve had historically. Although, I think as you know we’ve seen that fluctuate a bit quarter-to-quarter so I'm not sure exactly why that’s happening. But in typical right now our base is right now is about $0.12 may $0.12 to $0.13 of the Henry Hub. So we’ll have to try to do our best to match our hedge volumes with 1st of month volumes then again 1st of month volumes you got to be a little careful because that’s a firm commitment to deliver those volumes, which is another reason why we held some back on gas daily trading. But again like my previous comment as the base gets bigger, the higher the percentage that we can dedicate on 1st of month, the higher that correlation is with your hedges we think that perhaps a little less variability on a monthly basis from the price realization. On the hedge effect, which was also unusual we only got a penny improvement in our net price realization on gas, a big part of that was the February spike on NYMEX that we saw on the last day of settlement for the February contract, it shot north of $3.60. We got the benefit of the 1st of month gas that was priced very near that spike NYMEX price, but the gas daily portion suffered because again that price came off pretty hard. So doing our best to kind of minimize that variability and as I said as the base gets bigger we think we’ll have less fluctuation and variability.

[Joe Allman:]

Okay, very helpful guys. Thank you.

[Rob Turnham:]

Thanks, Joe.

[Operator:]

[Operator Instructions] Our next question will come from David Snow of Energy Equities Inc. Please go ahead.

[David Snow:]

Good morning. I'm wondering why your guidance on transportation cost is still midpoint $0.35 with these changes that you’ve negotiated what would that be on a kind of a current basis or go forward basis?

[Rob Turnham:]

Sure, David, this is Rob. We still have some Chesapeake operated wells that are planned. Those carry the higher rate. And if you remember our guidance on when we operate its ranges of $0.22 to $0.37. The $0.37 operated transportation charge is over in Thorn Lake, which is our Cason-Dickson area and we have those four wells, the two are flowing back today plus two additional wells planned for this year. So that’s really the driver it’s kind of a short-term issue when we move back to Bethany-Longstreet and we start drilling $0.22 to $0.26 wells then again that's going to continue to accelerate closure to what we are currently estimating the operated gathering fee to be.

[David Snow:]

So just kind of excluding that Chesapeake stuff you will be at the $0.22 to $0.26 gathering…

[Gil Goodrich:]

At Bethany-Longstreet, yes.

[David Snow:]

Okay. And I'm wondering if you can address why the first quarter taxes were $0.19 compared to your $0.09 guidance?

[Gil Goodrich:]

Yes, again it has to do with how much production and the status of that production. So all of our oil wells in the TMS are pass the severance tax abatement. And then again we didn't add the same number of wells that we had previously anticipated. Now our guidance is over the year, on a per unit basis and really not quarter-to-quarter. And so as we go from 37 million a day to 100 million a day exist rate, all of those wells are coming on at lower gathering or as low as what we've seen, and no severance tax. So all of those per unit numbers both just a product of math having higher volumes and therefore diluting down the historical production that carries the severance tax along with severance tax abatement is going to be very helpful. So, for example $0.19 in first quarter because of the reasons I just gave you we think get you -- you’re probably going to be closer to $0.10 in the second quarter, $0.06 or so in the third just gradually trending down as these new volumes are added.

[David Snow:]

Okay. And I believe I heard you say that you got 55,000 TMS acres, which compares to 65,000 at the 3/31 is that meaning you sold about 10,000 acres?

[Gil Goodrich:]

We didn't change -- it's 65,000 net acres, we only update that slide on the quarter. So that we are not stuck with acreage changes during the quarter. And we have a confidentiality agreement signed with the purchaser to not disclose the number of net acres that we're selling. We will tell you it is a small portion of the 65,000 net acres that went for that trade.

[David Snow:]

Okay, thank you very much.

[Gil Goodrich:]

Thanks, Dave.

[Operator:]

Ladies and gentlemen this will conclude our question-and-answer session. I would like to turn the conference over to Mr. Goodrich for any closing comments.

[Gil Goodrich:]

Sure, thank you, Alice. And everyone we appreciate your participation on this morning's call. We expect a little bit smoother quarter coming up here in 2Q and we look forward to reporting that to you in early August. Thank you very much.

[Operator:]

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