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Edited Transcript of GDPAO.PK earnings conference call or presentation 6-Aug-19 3:00pm GMT

Q2 2019 Goodrich Petroleum Corp Earnings Call

HOUSTON Aug 13, 2019 (Thomson StreetEvents) -- Edited Transcript of Goodrich Petroleum Corp earnings conference call or presentation Tuesday, August 6, 2019 at 3:00:00pm 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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* David Earl Beard

Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production

* Duncan Scott McIntosh

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

* John Phillips Little Johnston

Capital One Securities, Inc., Research Division - Analyst

* 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 morning and welcome to the Goodrich Petroleum's Second Quarter 2019 Earnings Conference Call. (Operator Instructions) 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, sir.

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

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Thank you, Chad. Good morning, everyone. Thank you for participating in our second quarter earnings call this morning. This morning, we reported strong second quarter results, and we look forward to sharing those results with you on this call this morning. In conjunction with the call, we have, again, prepared a slide presentation, and we invite you to follow the slide deck during the prepared remarks. You can access the slide presentation on the Goodrich Petroleum website entitled 2Q '19 Earnings Presentation.

The second quarter was a meaningful step forward in our strategy of growing shareholder value through prudent development of our core Haynesville assets. We have continued to grow production volumes quite rapidly, while also maintaining a conservative balance sheet. In the second quarter, production volumes grew by 35% sequentially over the first quarter to an average of 138.2 million cubic feet of natural gas and equivalents per day. Rob will give you more detail in just a minute, but an important component of our strategy is strong production volume growth while maintaining flat or fixed cost on the majority of our operating expenses, which, therefore, results in material reductions in per unit cash operating costs. The results of this strategy are well illustrated in the second quarter, where per unit cash operating expenses decreased by 35% versus the second quarter of last year and 23% sequentially versus the first quarter of this year to $1.02 per Mcfe.

Despite weakening natural gas prices, the strong production growth coupled with the significant decreases in per unit cash operating expenses led to strong cash flow growth in the second quarter. Operationally, we continue running one rig in the core of the Haynesville and Northwest Louisiana. And this morning, we announced the completion of our Melody Jones 20 H-1 well, which we recently completed as a 4,600 foot lateral in DeSoto Parish of Louisiana. The Jones is another excellent Haynesville well with a 24-hour IP of 22 million cubic feet per day on a restricted choke program.

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 have again included an overview of the company and our assets, which includes our core Haynesville shale position in Northwest Louisiana, where we continue to maintain a 10-year net inventory of delineated development locations, which contains over 1 Tcf of natural gas resource potential. While we maintain upside exposure to crude oil through our Eagle Ford and TMS assets, all of our current activity and plans are focused on the core Northwest Louisiana, Haynesville. The quality of our North Louisiana core Haynesville acreage is allowing us to continue rapidly growing our production, expand our cash margin while delivering top-tier returns with conservative yet improving debt metrics.

As I mentioned a minute ago, net production volumes increased materially in the second quarter to approximately 138 million cubic feet per day. When coupled with the significant decreases in cash operating expenses, EBITDA grew by 42% sequentially and 142% over the prior year to $21.5 million. Including the mark-to-market gain in the second quarter on our derivative position due to weakening natural gas prices, we reported net income in the quarter of $11.8 million and our return on capital employed, when annualized from the second quarter, resulted in 18%. On Slide 4, we again highlight our year-end 2018 SEC proved reserves of 480 Bcfe, which had a present value discounted at 10% of $418 million.

On Slide 5, we provide an updated cap table as of the end of the second quarter. During the second quarter, we closed on a new and expanded senior credit facility with an initial borrowing base of $115 million, which allowed us to redeem all of our old convertible second lien notes for approximately $57 million, issued $12 million of new second lien notes and significantly reduce our net cost of capital. Our second quarter annualized EBITDA equals $86 million and compared with approximately $95 million of net debt results in net debt-to-EBITDA of 1.1x.

Turning to Slide 6. We have updated our quarterly production chart to illustrate our production growth over the past couple of years as well as the significant step-up in volumes during the second quarter of this year, where, again, we averaged just under 140 million cubic feet per day.

On Slide 7, we provide detailed volume and price information on our current natural gas and crude oil hedge positions. As you can see, we are very well hedged through the remainder of this year with 100 million cubic feet of gas per day hedged at $2.89 per Mcfe, which represents a little over 72% of the reported second quarter volumes hedged at these prices. We continue to watch the natural gas markets closely, and in particular, the longer-term strip prices for both capital planning and incremental hedging opportunities. Detailed data on our 2019 guidance is shown on Slide 8, which includes the production guidance for the full year with an average of 135 million to 145 million cubic feet per day.

Given our second quarter volumes and current production, we remain confident in these numbers based on our current plans for the second half of the year. At the same time, it is our standard practice to review our preliminary full year plans on a quarterly basis with our board and to make any appropriate adjustments based on results as well as current and future market conditions. In addition, the guidance provides the anticipated ranges for per unit cash expenses of LOE, taxes, transportation and cash G&A, each of which was within or at the low end of the range in our reported second quarter results. Finally, we have made a minor adjustment to our 2019 gross and net well counts as well as cadence to accommodate our participation in 3 non-operated wells in the Bethany-Longstreet Field for a 25% working interest. This change results in a slight increase in gross wells, a slight decrease in net wells, but no meaningful impact on our production guidance.

And with that, I'll now turn the call over to Rob to provide you some more detailed review of our second quarter as well as highlight several key trading measures for the company.

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

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Thanks, Gil. Revenues totaled $31.9 million in the quarter with an average realized price of $2.35 per Mcf, $65 per barrel and $2.54 per Mcf equivalent. When adjusted for our settled hedges, revenues were $33.9 million with an average realized price of $2.70 per Mcf equivalent. Our per unit cash operating expense continue to drop in the quarter, as Gil said, decreasing by 35% over the prior year period and 23% sequentially to $1.02 per Mcf equivalent.

LOE decreased sequentially by 33% to $0.24 per Mcfe. Production and other taxes by 29% sequentially to $0.05 per Mcfe. Transportation and processing decreased by 8% sequentially to $0.46 per Mcfe and cash G&A decreased by 33% sequentially to $0.27 per Mcf equivalent.

Capital expenditures for the quarter totaled $25 million, of which 98% was spent on drilling and completion costs associated with Haynesville Wells. As to our plans for the rest of the year, we remain on schedule with our preliminary capital expenditure budget, as previously announced, which will continue to be subject to quarterly board review and approval.

Interest expense totaled $3.4 million in the quarter, which included cash interest of $1 million incurred on the company's revolver and noncash interest of $2.4 million incurred on the company's convertible notes. The noncash interest expense was comprised of $1.4 million of paid-in-kind interest and $1 million of amortization of debt discount and debt issuance costs associated with the company's old second lien notes for a portion of the quarter and new 12 million second lien note issuance.

With the recent refinancing of a majority of the old second lien notes, the company's blended average interest rate going forward will be lower based on the current interest rate environment. Moving back to our slide deck. As we have highlighted before, we've included several slides beginning with Slide 9 that show how we compare to a 56 company peer group.

Our cut-off date for the analysis was July 30. And for the first time, we've included return on capital employed as our first comparative slide, as we view that as the most important metric today. As you will see on Slide 9, our return on capital employed of 18% for the quarter ranked third in the 56 company peer group. The high return on capital employed is obviously driven by the very high rate of return wells we are drilling and completing in the Haynesville.

Moving to Slide 10. If we were to show true capital efficiency, which is defined as CapEx to growth in volumes, we would likely be at the very top of the rankings, but we believe a more compelling evaluation is CapEx to growth in EBITDA, as everyone is focused on returns versus production growth. Again, as you can see, we ranked third on this modified capital efficiency analysis as our returns, including our hedges, are extremely competitive even when comparing to oil basis. Under this modified capital efficiency analysis, there are fewer companies in the peer group due to fewer companies actually growing EBITDA year-over-year. 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. Even though our capital efficiency and return on capital employed are near the top of the 56 company peer group and our debt-to-EBITDA is conservative, we only trade at approximately 2.5x consensus enterprise value to 2019 EBITDA, as shown on Slide 12.

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 the year with 214 gross, 99 net locations on spacing of 880 feet between wellbores, and we now expect to complete 12 gross, 9.3 net locations this year, which yields a 17.8 year gross, 10.6 year net inventory life in North Louisiana alone. We continue to focus at a minimum on replacing the inventory that we drill with bolt-on acquisitions as we have done in the past.

The acreage in North Louisiana is approximately 75% undeveloped and 73% operated. We have gridded 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. Our estimate of 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone compares to year-end '18 booked proved reserves in North Louisiana of 471 Bcf equivalent. We also maintained 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. All of our acreage has now been derisked, and we're in development mode, drilling predictable wells in proven areas, connecting wells into existing pipes with excess capacity. We have allocated approximately 2/3 of our 2019 capital expenditure budget to Bethany-Longstreet and the other 1/3 to the Thorn Lake area, and our acreage is derisked with exceptional wells on or offsetting our acreage.

We have updated our decline curve slides beginning on Slide 16 and now have even more wells to compare. On Slide 16 and 17, we are tracking 265 4,600 foot laterals with average proppant concentration of 3,125 pounds per foot. As you will see, the older wells are underperforming the newer wells, as average proppant is lower on the older wells than the newer wells. Our wells shown in green were stimulated with over 4,100 pounds of proppant per foot and are not only a good bit better than the industry average composite curve, they exceed our 2.5 Bcf per 1,000 foot curve by a good bit.

In fact, our more recent wells are pulling up the composite curve over time, which we expect to continue. Slides 18 and 19 reflect our 7,500-foot curves, where we now show a composite of 178 industry wells with average proppant concentration of 3,000 pounds per foot, which fits 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 with approximately 2,500 pounds per foot and the newer wells averaged 3,354 pounds per foot, which again, we expect will pull up the curve as the newer wells with higher proppant concentrations flow through over time. Our more recent operated wells, which carry higher proppant concentration, are running well above the 2.5 Bcf per 1,000 foot curve.

Slides 20 and 21, which now show a composite result from 152 approximate 10,000 foot laterals with an average of close to 3,000 pounds per foot of proppant are also tracking our 2.5 Bcf per 1,000-foot type curve until the older wells with lower proppant concentration kick in a little over 2 years out. Our 7 wells, which average approximately 9,800 feet of lateral and 3,400 pounds per foot of proppant are for the most part tracking our 2.5 Bcf per 1,000-foot curve. We believe this data validates the quality of our acreage and optimum completion technique and maximizes cash flow generation, which is the #1 driver in our corporate strategy.

In general, there's a high correlation between longer laterals, [tighter] interval spacing and higher proppant concentration to EUR, but we are more focused on the returns we're generating versus just EUR, as return on capital employed is our primary objective. Our economics, as shown on Slides 22 to 24, show how exceptional this play is at reasonable prices. If you bake in our hedges of 100 million cubic feet per day at $2.89 through the end of the year, we should average pre-differential in the 250 to 275 range, which would generate approximately 55% IRR at the midpoint for our average lateral length through the year using our 7,500-foot curve. We capture the early time outperformance on our economics for our wells. And when you combine that with high netbacks, very low LOE initially at less than $0.05 per Mcf. And no severance tax until the earlier of 2 years or payout, our returns are very competitive with any basin, as evidenced by our 18% return on capital employed for the quarter at similar pricing.

In summary, although we can't control commodity prices, we have a nice hedge book that at the midpoint of guidance locks in at over 70% of our annual volumes at $2.89 and our per unit cash operating costs are falling as expected, driving very good margins, capital efficiency and a superior return on our capital employed. With that, I'll turn it back to Chad for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) The first question will be from Welles Fitzpatrick with SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [2]

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Can we get a update on the divestitures? Are you guys still thinking of Eagle Ford and TMS as marketable? And what about ART? I see it kind of got bundled into the core Haynesville position on your slide deck. Is that signaling that maybe that's a little bit more core, a little bit more moved up in the to-do list?

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

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This is Gil. I would say, in the Eagle Ford, we remain where we've been for quite a while now, which is that we're open to proposals. It's something that we don't plan to necessarily market through a data process, but we are open to outright sale or JV, if the price is right for someone who's interested. And I would say, there has been a pretty strong uptick in activity around our acreage over the last 6 to 12 months, and we're watching those results pretty carefully. So I think we're pretty comfortable just watching that. In the meantime, if someone comes with something that's meaningful, we'll certainly consider it and take it to our board. As to the TMS, as you're I'm sure aware, Australis and a small Australian company has been active with a program built growing TMS wells. I'm not sure exactly where there are. They are probably well 5 or 6 into that development program. We're watching that very carefully. I think all of our acreage there is HBP, so we're kind of comfortable watching those results as well. And in addition, you've got the Louisiana Austin Chalk play going on, which has the potential to spread over some of our acreage over time. So we're comfortable there, just watching that. No active process to sell. And at the ART, we're -- we like the acreages, as Rob mentioned in his comments. We got both the Bossier and the Haynesville there. Still going to continue to focus for the foreseeable future in Northwest Louisiana, but that's a position we're happy to hold on to.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [4]

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Okay. Okay. That makes sense. And then I guess, just sort of a higher-level question. Can you give your thoughts on the recent A&D in the basin? I mean, Sabine and Covey. Do you see that as a start of a trend there or more of a kind of investor driven one-off transactions?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [5]

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Yes, Welles, this is Rob. Certainly, the Covey Park-Comstock transaction, we viewed as a very reasonable transaction, good value for both. There were synergies. There were reasons to do it. And we thought the metrics looked pretty favorable. If you compare those same metrics to us, our position in the basin. Certainly, a lot of interest in exploring ways to perhaps consolidate. The question is just are there cash buyers or stock buyers and -- or stock merge candidates. So we'll just have to see how that plays out. And likewise, the Sabine transaction, again, we thought was a nice valuation. A lot of their acreage is East Texas, obviously. Actually all of their acreage is East Texas, and some of it is Cotton Valley Travis Peak acreage. So not exactly apples-to-apples with us 100% Haynesville in North Louisiana, but again, a very favorable transaction we thought for the Sabine management team. So we'll just have to kind of let it play out. In the meantime, it's head down and execute and continue to perform like we've been performing. Because, as you know, a Tcf with reserve exposure already locked down is basically a company maker for us and make sure we don't take our eye off the ball. And the last thing we want to do is lever up to buy more acreage that you put in the back of the inventory when this thing is working extremely well.

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Operator [6]

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Our next 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 [7]

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On the reshuffling of the quarterly completion cadence, I know you've kept your full year guide the same, but any color on what that kind of growth in the third and fourth quarter looks like with that reshuffling?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [8]

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Yes, Dun, this is Rob. I think, as we've said, a little less growth in the third quarter versus the fourth quarter is where we would stand. And I think at the end of the year, if you had the growth and the volumes that we've guided to as your yearly total, that would probably be the best way. We haven't given specific quarterly guidance because the 3 wells that we participate in as a non-operated working interest owner, we don't have quite the same control over timing. We have no control over timing of those completions. We know when they expect to be completed, but that's what -- that was one of the reasons why we were a little hesitant giving 3Q and 4Q guidance in the -- within the call. We're confident with our ability to stay within the previously issued guidance. So I would just pencil in a little growth in the third quarter and more growth in the fourth that would ultimately get us somewhere within the guidance range that we've given.

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [9]

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Perfect. And then I noticed CapEx was a little lighter than where we were in the street this quarter. Is it kind of safe to assume that, that might be biased a little more towards the lower end of your $99 million range?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [10]

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Yes, I think, we're within the range. Again, a lot of this is timing issues as to when you're actually capturing the costs. And as we've said, that completion cadence, we're obviously capturing drilling costs when occurred. And then the completion costs can vary, obviously, based on timing. So I think we would be more comfortable in the midpoint of the CapEx guidance versus the low end. We've always talked about our budget being a bit more front-end loaded than back-end loaded, and that's still the case.

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Operator [11]

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(Operator Instructions) Our next question comes from Phillips Johnston with Capital One.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [12]

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I just wanted to follow-up actually on that last question on CapEx for the year. It looks like your well count for the back half of the year is pretty similar to the first half of the year. And as you mentioned, I guess, the cadence is a little bit more front-end loaded. So what's the main driver for CapEx coming down in the back half of the year? Is it something on the cost front? Or is it more just sort of like a timing issue?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [13]

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Yes. So this is Rob, again, Phillips, and thanks for the question. So for example, we have -- obviously, had captured quite a bit of drilling costs at the end of the second quarter on wells -- on a well in particular that we're completing in the third quarter, so a little bit of it is just timing. But I think if you add the two, we're about $55 million in the first quarter -- I mean, the first half of the year. If you add $40 million in the back half, that would get you the midpoint of guidance. And it, again, we're comfortable at this point in time that, that's an appropriate way to look at it. So it just -- it varies based on when you're accruing for the drilling cost versus capturing the entire well cost.

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Operator [14]

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The next question will be from David Beard with Coker & Palmer.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production [15]

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I'll follow-on to the previous question. What do you think a maintenance CapEx would number would look like holding fourth quarter exit rate production flat going into 2020?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [16]

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Yes, David, I'll give you range here. We've kind of done some work around that. Obviously, it depends on exactly where the fourth quarter works out. I would tend to maybe stay closer to where our second quarter volumes are, and we think somewhere in the, call it, $60 million to $70 million range is something that we could maintain that volume, which would, obviously, have us generating a fair amount of free cash flow in 2020. I might just add, we've got a number of options for the company in terms of our 2020 planning. We've obviously not issued any guidance. The board will make the decision on the 2020 plans at our December board meeting. We'll be discussing that with the board in pretty good detail here in a few weeks, but great optionality from our view with a current hedge position that kind of equals about 28% of second quarter volumes already locked down for next year. Not as much as we'd like, but certainly not a 0 on our hedges for next year. It's probably somewhere in the neighborhood of about $2.80 on an Mcf equivalent basis. So we could dial back, generate free cash flow. We could just maintain current volumes, either where we are today or fourth quarter volumes, or we could decide we want to be a little bit more aggressive. And I think the big driver for the board is going to be exactly where the strip prices look like for next year and what's our ability to add to our hedge position.

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Operator [17]

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

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [18]

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Thank you, Chad. Thank you, everybody, for your participation this morning. We look forward to the third quarter and reporting those results to you in early November. Thank you.

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Operator [19]

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