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Edited Transcript of GDPAO.PK earnings conference call or presentation 5-Mar-20 4:00pm GMT

Q4 2019 Goodrich Petroleum Corp Earnings Call

HOUSTON Mar 26, 2020 (Thomson StreetEvents) -- Edited Transcript of Goodrich Petroleum Corp earnings conference call or presentation Thursday, March 5, 2020 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Robert T. Barker

Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO

* Walter G. Goodrich

Goodrich Petroleum Corporation - Chairman & CEO

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Conference Call Participants

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* Duncan Scott McIntosh

Johnson Rice & Company, L.L.C., Research Division - Research Analyst

* John Phillips Little Johnston

Capital One Securities, Inc., Research Division - Analyst

* Noel Augustus Parks

Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good day, and welcome to Goodrich Petroleum Fourth Quarter and Year-End 2019 Financial Results Earnings Call. (Operator Instructions) Please note, the event's being recorded. I'd now like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [2]

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Good morning, everyone. Thank you for participating in our fourth quarter and full year 2019 earnings call this morning.

The current natural gas market presents challenges for all natural gas producers, and we are no exception. However, we are blessed with a strong balance sheet, which currently represents a net-to-EBITDA of approximately 1.25x when annualizing our most recent quarterly EBITDA. This relatively low level of debt, the very high quality of our Haynesville assets and inventory and our very good hedge position provides us great flexibility to execute and deliver positive results during this period of low natural gas prices as well as to prepare us to resume higher levels of growth when the market has recovered and provides more compelling returns on our capital.

We are watching the markets closely and routinely discussing strategic options with our Board to ensure we execute the right plan and strategy for our shareholders during this period of reduced commodity prices. Our hedging position continues to provide us with excellent protection from the current low prices and delivered almost $10 million in realized derivative gains in 2019.

Our forward hedge position through 2020 covers approximately 50% of current production at a minimum blended floor price of approximately $2.60 per Mcf. While our realized field level natural gas prices averaged just $2.14 per Mcf in the fourth quarter, when factoring in the benefit of our realized hedge gains on our natural gas derivatives, net realized prices were $2.53 per Mcf. In addition, the quality of our Haynesville assets is demonstrated by the continued improvement in well performance, reserves and returns on capital investments, all of which we will review with you this morning.

While we currently are maintaining a 1-rig drilling program in the Haynesville, we retain the flexibility to pick up or slow down the pace of development as well as the cadence of completions. Any changes to our capital plans will be made after careful review and deliberation with our Board of Directors and done on a quarterly basis. We'll be meeting with our Board next week for our March meeting.

We anticipate generating free cash flow in 2020. And any potential changes in capital planning will be done with an eye towards further strengthening the company, its balance sheet and achieving the optimum amount of free cash flow during this period of depressed natural gas prices. As has become our practice, we have, again, prepared a slide presentation and we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on our Goodrich Petroleum website with the tab entitled 4Q 2019 Earnings Presentation.

I will now turn to the slide presentation for those of you who would like to follow along and our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2.

On Slide 3, we are now providing all of our stakeholders' information regarding our environmental, social and governance statistics. We hope this information is helpful. And we will continue to strive to provide the most current and transparent information we can as it pertains to ESG.

On Slide 4, we have again included an overview of the company and our assets, which highlights our core Haynesville Shale position in Northwest Louisiana, where our inventory life has grown to approximately 16 years of net inventory as we have slowed our pace of development in response to current lower natural gas prices. This inventory contains over 1 Tcf of natural gas reserve potential and a clear runway of well delineated, de-risked development for years to come.

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%. Our reserves at year-end averaged approximately 2.5 Bcf per 1,000 feet of lateral for all of our higher proppant, tighter frac interval space wells that we have drilled over the last 3 years.

Performance from our refined completion designs, lower cost of goods and services, very low LOE and our hedge position are collectively delivering very solid returns. For full year 2019, our return on capital employed, or ROCE, was approximately 12%. Rob will show you how that compares with our peers in just a moment.

Solid production performance, cost containment and approximately $3.4 million of realized hedge benefit delivered EBITDA in the fourth quarter of approximately $21 million. For the full year, we achieved $79 million in EBITDA. We, again, delivered top-tier capital efficiency while maintaining low leverage on our balance sheet.

On Slide 5, we present our year-end 2019 SEC proved reserves, which grew to 517 Bcf with a present value of just under $300 million using SEC-mandated pricing and discounted at 10%. As you will see from the pie charts, our proved reserves are almost exclusively natural gas and associated with the core Haynesville Shale assets.

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

Turning to Slide 7. 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 the fourth quarter. In addition, we provide the midpoint of our current plan and guidance for 2020.

On Slide 8, we provide detailed volume and price information on our current natural gas and crude oil positions. As you can see, we are very well hedged through all of this year with a combined 70 million cubic feet of natural gas hedged at a blended average floor price of $2.60 per Mcf, which provides solid protection against the currently 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 planning.

Finally, we provide our current 2020 guidance on Slide 8, 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 $60 million. We have also updated our guidance for the expected basis differential in Haynesville as well as estimates of our 2020 per unit cash cost on a per Mcfe basis. And in addition, we do provide the anticipated well count and completion cadence for you on a quarterly basis.

I'll now turn the call over to Rob.

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [3]

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Thanks, Gil. As 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 million to 145 million cubic feet equivalent per day, primarily driven by the participation in a nonoperated well in the quarter that was unexpected at the time of our previous guidance.

Revenues adjusted for cash settled derivatives totaled $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. Our per unit cash operating expense, which is defined as per unit operating expenses, excluding DD&A and noncash G&A dropped to $0.97 per Mcfe in the quarter, generating a cash margin of 62%.

Capital expenditures for the quarter totaled $18.5 million, of which 99% was spent on drilling and completion costs associated with Haynesville wells. The fourth quarter capital expenditures were higher than our previous guidance, again, due to the participation in 1 previously unanticipated non-op Haynesville well in the quarter. Capital expenditures for the year totaled $98.4 million and 99% on drilling and completion costs in Haynesville.

We conducted drilling or completion operations on 16 gross wells in 2019 and added 3 gross, 1.85 net and 9 gross, 7.2 net wells during the quarter and year, respectively. We previously gave guidance for 2020 in December, but as Gil said, it is subject to quarterly review by the company's Board of Directors with the primary goal being cash flow generation from modest growth in volumes, hedge realizations and a continuing reduction in cash operating expenses.

The interest expense totaled $2 million in the quarter, which included cash interest of $1.2 million incurred on the company's revolver and noncash interest of $800,000 incurred on the company's convertible notes. The noncash interest expense was comprised of $400,000 of paid-in-kind interest and $400,000 of amortization of debt discount and debt issuance costs, primarily associated with company's second lien notes.

Moving back to our slide deck. As we have highlighted before, we've included several slides beginning with Slide 10 that show how we compare to our peers. As stated earlier and as you will see on Slide 9, our return on capital employed for the year was 12.4%, despite very low commodity prices, which ranks fourth out of the 39 companies in our peer 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 1.5x or less, and we are below this marker currently and expect to remain there in the foreseeable future.

Even though our capital efficiency and return on capital employed are near the top of the peer group and our debt-to-EBITDA is conservative, we only trade at approximately 2x enterprise value to EBITDA as shown on Slide 12, which, needless to say, is an extremely low multiple versus our peer company average of over 4x.

As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville, beginning on slides 13 and 14. We entered 2020 with 22,000 net acreage in the core of the play and 208 gross, 91 net locations on spacing of 880 feet between wellbores for a net inventory life of approximately 16 years at current pace as Gil stated earlier. These 208 gross, 91 net locations are all in the core of North Louisiana.

Our acreage in North Louisiana is over 70% undeveloped and 73% operated. We have gridded our acreage and expect to continue to swap acreage or drill joint wells with offset operators to maximize our returns. We estimate over 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral and 800-foot spacing in North Louisiana alone versus year-end '19 booked reserves in North Louisiana, and those are proved reserves of approximately 510 Bcf equivalent. We also maintain approximately 3,000 net acres held by production in the Angelina River Trend of the Shelby Trough for future development. The Haynesville and Bossier formations are both prospective on our Angelina River Trend acreage.

As shown on Slide 15, all of our acreage has now been de-risked and we are in development mode, drilling predictable wells in proven areas and connecting these wells into existing pipes with excess capacity. We've allocated approximately 90% of our 2020 preliminary capital expenditure budget to Bethany-Longstreet and the other 10% to the Thorn Lake area.

We continue to outperform our type curves. And on Slide 16, we are tracking our wells versus 309, 4,600-foot lateral industry wells drilled in the core. Industry pumped an average of 3,100 pounds per foot on these 309 wells. But as you can see, the older wells are underperforming the newer wells as average proppant is lower on those older wells.

Our 6 wells, shown in green, were stimulated with approximately 4,100 pounds of proppant per foot and tighter cluster spacing and interval spacing. And not only are they quite a bit better than the industry average composite curve, but our composite curve exceeds our 2.5 Bcf per 1,000-foot curve to an estimate of approximately 2.7 Bcf per 1,000.

There is a clear correlation between proppant loading and cluster and interval spacing, and we expect our more recent wells to pull up the composite curve over time as we reached completion optimization over the last 18 months.

Slide 17 reflects our 7,500-foot curve, where we now show a composite of 225 industry wells with average proppant concentration of approximately 3,000 pounds per foot, which for the most part fits our 2.5 Bcf per 1,000-foot type curve. The older wells included in the industry composite curve that are underperforming the curve in the later years are a handful of under-stimulated wells with proppant loading of approximately 2,300 pounds per foot.

Like the 4,600-foot laterals, our more recent operated 7,500-foot wells are outperforming materially the composite estimate of approximately 2.8 Bcf per 1,000 feet due to higher proppant concentration, and again, tighter cluster and frac interval spacing.

Slide 18, which now shows a composite result from 225, 10,000-foot laterals with an average of 33,000 pounds per foot of proppant are, for the most part, tracking our 2.5 Bcf per 1,000-foot type curve. The older wells here with lower proppant concentration kick in a little over 2 years out and are falling below the curve, once again, tight correlation with proppant loading and EUR.

Our 9 wells, which averaged approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant are, for the most part, tracking our 2.5 Bcf per 1,000 curve.

We believe our well performance speaks for itself and is driven by a number of factors: quality of our acreage, and no question we're in some of the best rock in the play; an optimum completion methodology, where proppant concentration, cluster and interval spacing and pump rates provide a material difference in results; and flowback technique that minimizes daily drawdown, flattens the decline curves, provides high recoveries of gas in place, and most importantly, maximizes returns.

We have updated our economics as shown on slides 19 through 21 to reflect our outperformance and to also include a $2 gas price on the low end of the range. Our economics have improved on our 4,600 and 7,500 foot laterals due to outperformance. As you can see, even at $2.25 gas price, we can generate a 40% IRR on our average 7,500-foot lateral wells.

As a reminder, the Haynesville economics are driven by high volumes, attractive netbacks relative to Henry Hub as compared to other gas basins, low service costs, low lifting costs and severance tax abatement until the earlier of 2 years or payout of the well.

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 and a unit cost structure that is declining, creating competitive margins.

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

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Questions and Answers

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Operator [1]

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(Operator Instructions) First question comes from Dun McIntosh with Johnson Rice.

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [2]

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I wonder if you could provide a little more color around the optionality in your 2020 program. Just running 1 rig, is it -- would it be -- if prices do remain lower, would it be laying that rig down for a while and maybe picking up or looking for some more non-op opportunities? Or kind of how do you think about that with, obviously, free cash flow kind of being the driver in this environment?

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [3]

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This is Gil. Thanks, Dun. Well, lots of great flexibility. We do have some areas, Rob alluded to in his prepared remarks, we had a kind of an unexpected non-op proposal come up to us on really good acreage, and we didn't want to let that opportunity get away. So 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 around the exact timing of that. We will backfill around with our operated activity for whatever that level of non-op participation is. That being said, we've got great flexibility and we're running the 1 rig now. I think one of the things that we could do is maybe just build some DUCs, keep the rig for a period of time, drill a few DUCs and complete them in a cadence that makes sense with natural gas prices. So as I alluded to in my remarks, we'll be reviewing a number of different scenarios with the Board next week. And staying with the base case guidance we've provided is one of those options, obviously. Then we may decide that we want to slow down a little bit. I really don't think you'll see a pickup in the pace at this point in time.

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [4]

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And Dun, this is Rob. I'll add to that. As far as swaps, we continue to do that. We think there's a chance of perhaps picking up a little bit of incremental bolt-on type acquisitions through certain swaps, but nothing definitive to talk about now.

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [5]

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Okay. Great. And then maybe from a little bit higher-level macro question. The Haynesville rig count was surprisingly resilient through the back half of '19 and recognizing that private operators drove a lot of that. But kind of what are you seeing now? And how do you think about the Haynesville activity in context of kind of the broader natural gas space? And what's your thoughts on kind of looking out 12, 18 months with respect to price and kind of the ideology, maybe at oil prices -- fixed oil prices. Just kind of any color you can give there. And what -- how you...

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [6]

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Sure, this is Gil. I'll start, and then Rob can chime in. Obviously, our crystal ball is 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 hand scoping that to specific Haynesville-only rigs. Sometimes, if you look at just kind of general areas, you'll pick up some Cotton Valley activity in non-Haynesville stuff. Our internal numbers suggest that the Haynesville rig count hit about 60 rigs at a peak last year. In the most recent week, it's at 38. My personal belief is that, that number comes inside of 30 and probably does fairly soon. And we'll be -- ultimately, this year will be one of those really you cannot believe that we'll be laying down a rig and building some DUCs, as I said, and completing some wells later in the year. I can't help believe given where natural gas prices and strip prices are that 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 '21, either the strip is going to come up or CapEx levels are going to come down in terms of natural gas activity.

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [7]

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And the only thing I'll add, Dun, is we belong to a consortium which includes most of the operators in North Louisiana. And the commentary is consistent with what Gil just described, which -- and it includes quite a few privates that people don't have intelligence on. So the direction is clearly rigs coming out of the basin, which we think, obviously, is a real positive on declines in supply. Not just there, but you'll see them continuing in the Marcellus, which ultimately fixes the commodity, the strip ought to go in contango, and then you'll have a real reason for people to kind of jump back into the space.

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [8]

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All right. Great. And congrats on a strong '19 and a solid '20 outlook.

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [9]

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Thank you, Dun.

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Operator [10]

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Next question comes from Welles Fitzpatrick of SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [11]

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Can we talk a little bit more about the divergence in the curves on the lateral length? I mean, more specifically, I'm a little bit surprised that the mid-ranger would be better than the 10,000 footer. How -- I guess, how clean is that data? I mean it's -- how many wells do you have in each sample set? And then some of that may be kind of -- the fact that you don't necessarily have as many maybe 4,600 as you do 10,000 footers, et cetera?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [12]

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So this is Rob. I'll take a shot at that. If you look at -- so for example, the 4,600-foot laterals, 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 18 months, those wells are producing far in excess of the older wells they kick in at, call it, 20 months. So all we've done is taken the composite of those wells that we show on that graph and model that out using standard terminal decline rates as used by Netherland, Sewell. But we think there's upside to the 4,600-foot case up and above -- over and above the 2.7 Bcf per 1,000 that we've used in the updated economics. We'll tell you one other thing that we see some benefit there, which is the ability to nail your capital expenditures right on your AFE. Obviously, the shorter the lateral, the higher the probability of meeting or beating those cost estimates. As to the 7,500, we've made great progress there. That's -- those economics have moved a good bit. The previous economics, for example, on a 7,500-foot lateral were 45% IRR at $2.50, and that's 59% now. So really, almost 15% incremental IRR. And like the 4,600-foot laterals, we started tightening up our frac interval spacing, increasing our profit loading a bit and similar to the 4,600-foot curve you see over the early 18 months, those wells were outperforming. And again, should pull up the curve over time as those wells flow through the curve. So we feel very good about that. When you look at the 10,000-foot laterals, we have similar proppant probably than what we have before -- the proppant loading, again, is in a similar range. The interval spacing on average is about 125 feet per stage versus a little less than that on the 4,600s. So again, and even the 7,500s, the better wells that pull it up or even tighter than that at a 100-foot interval. So clearly, when we do linear regression, very good correlation on proppant per foot and interval spacing per foot. And we think that's shown up here. The only problem with tightening your intervals on the 10,000-foot laterals to 100 feet or 110 is just the cost of the well. And as we've talked before, any time you extend past 7,500 feet, if you have the need to trip out a hole and replace bottom hole assembly or bit, you're adding to your cost of the wellbore. So -- and it's a 3- or 4-day turnaround. So we -- all things being equal, you could say your 7,500s are your sweet spot in that you have less risk on exceeding your AFE and you're generating very good rates of return that are actually similar, if not better, than your 10,000-foot laterals because the results have been better.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [13]

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Okay. That makes sense. So it sounds like the 4,600s have probably the most room to improve versus the rest of them. But can you remind us how many of your locations are 7,000 footer or greater?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [14]

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Yes, it's a moving target. I would say, depending on how we structure that, you could probably get 40%, 50% longer laterals. And then the 4,600s would be, call it, 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 a -- be more like 1/3, 1/3, 1/3. But we've -- but if you just grid it out right now, we have plenty of 4,600s to drill. And that's why spending -- our well costs, in some cases, are probably slightly higher than others. But we're outperforming those other companies because of our well design. And when you really do the math and you run the economics, yes, you can save money by pumping less profit and you're going to automatically make poor wells. And we just see the real benefit from the proppant loading in tight interval spacing.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [15]

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Okay. That makes sense. And then kind of looking into 2020, you've talked about this a little bit. But can you talk to the non-op visibility from a CapEx standpoint? And I assume, given your prior comments that, if anything, that would be biased downwards?

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [16]

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So this is Gil, Welles. First of all, it's very difficult to give you a whole lot of clarity because as we just happened in this last quarter, we had something pop up that we didn't even know. 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 casing and completion cadence to kind of backfill around that from a capital perspective and blend it out on a quarterly basis.

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Operator [17]

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Next question comes from Phillips Johnston, Capital One.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [18]

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Thanks for the disclosure around PDP, PV10 at year-end. I think it speaks to the -- yes, I think it speaks to the value here. My question is, what would that approximately $600 million of PDP value look like if you ran it at sort of a flat $2 gas price instead of the SEC deck?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [19]

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Yes, we've not done the sensitivity yet. We've been kind of running around with our head cut off, getting ready for the 10-K and the call. I'll have to get back beyond that sensitivity, Phillips.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [20]

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Okay, Rob. And then you guys gave us some good color around just the quarterly cadence of net well props for the year. So just wanted to see what that schedule means for quarterly volumes at least from a directional standpoint? I think your guidance implies a full year average, it's around 3% above kind of that fourth quarter '19 exit rate. So should we expect fairly even quarterly sequential growth throughout the year versus that exit rate? Or is there some lumpiness in production?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [21]

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Yes. There is going to be a little lumpiness because if you look at our Slide #9, current guidance has us only completing 1 net well in the first quarter. And then 2.3 net in the second, 1.8 in the third and 0.7 in the fourth. So as our budget currently sits, it's going to be a surge kind of in the second and third quarter. And we'll try to give a little bit more guidance. As Gil said, we've got a Board meeting next week, and we'll see if this changes at all. But yes, it will be -- it certainly would be lumpy and peaking in the second and third quarter.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [22]

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Okay. So for Q1, should we expect maybe down a little bit and then surging in second and third quarter? And then maybe down a little bit in Q4?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [23]

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Yes. Exactly right. Directionally.

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Operator [24]

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Next question comes from Noel Parks, Coker & Palmer.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [25]

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I just wanted to check in, sorry if you touched on this already, but the non-op well that you had in fourth quarter, what was the working interest on that?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [26]

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Yes, likely close to 25% working interest. But we incurred all the capital in December. So -- and that acreage, by the way, was kind of near the Louisiana border in East Texas. If you -- someone else called me and said, "It looks like you had an increase in reserves in East Texas." It was basically just our interest from that well.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [27]

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

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [28]

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This is Rob. I'll take the first stab at it. We've seen -- and we have hedging consultant group that advises us on some of that. I think the numbers are really moving. If you assume 1 million barrel a day growth in the Permian, which we would buy us lower than that based on where prices are, where -- how conservative the banks are, the capital markets being somewhat closed, we think it's going to be less than that. And we've seen 3.5 Bcf a day or thereabouts of associated gas growth, if my memory serves me, for the 1 million barrel a day, which we think should be biased low. And of course, the problem is the takeaway is not there that capture all of those volumes. So we think the true output coming from the basin is going to be a good bit lower than that. If you then look at the Haynesville and Marcellus currently in decline, and we don't think it's freeze off. It's certainly not 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 than clearly we're declining there and we're going to have less associated gas. And as long as demand remains and then certainly coronavirus hasn't helped, and we're suffering through some oversupply on LNG currently. As long as that kind of gets back to where we think it should be, then the back half of this year ought to be better for gas prices and likely for oil prices as well. And as I said, Gil could chime in, but I -- what we really need is people to live within their means, let's see the rollover continue on supply. And then they'll reach a point in time where we think the strip will go in contango, then the industry is more investable at that point.

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Operator [29]

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(Operator Instructions) This concludes our question-and-answer session. I'd like to turn the conference back over to Mr. Gil Goodrich for any closing remarks. Please go ahead.

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [30]

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Thank you very much, everyone. We appreciate your participation this morning, and we look forward to reporting our first quarter 2020 reports to you in early May. Thank you.

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Operator [31]

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