Goodrich Petroleum Corporation
Q3 2014 Earnings Call Transcript

Published: 4 Nov 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Goodrich Petroleum Corporation Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Gil Goodrich, Vice Chairman and CEO. You may begin.

[Walter G. Goodrich:]

Thank you, and good morning, everyone. Welcome to our third quarter earnings conference call. I'll begin with an introduction of the management team that's on the call with us. Mr. Pat Malloy, the Chairman of the Board; Rob Turnham, President and Chief Operating Officer; Mark Ferchau, Executive Vice President and Director of all our engineering and operations; Mike Killelea, Senior Vice President, General Counsel; and Jan Schott, Senior Vice President and Chief Financial Officer. Daniel Jenkins is with us in spirit this morning. However, he's currently at the hospital with his wife expecting his second child within the next couple of hours. As is our practice, we'd like to make everyone aware that the comments we may make and the answers we may give to questions during this teleconference may be considered forward-looking statements, which involve risks and uncertainties, and we have detailed those for you in our SEC filings. During this morning's call, we will refer to a presentation that we have posted on our website at www.goodrichpetroleum.com under presentations and events, and shown as supporting materials for the Q3 earnings call presentation. For those of you who wish to follow along with us, we suggest that you open and access that now as we will get into that in just a few minutes. During the third quarter, we continued to make meaningful progress in the Tuscaloosa Marine Shale or TMS. We and our industry partners have delivered an increasing number of consistent high rate wells, free of major mechanical or operational problems, and further demonstrated the repeatability of the play within the rapidly emerging core fairway. To that end, we announced 2 more very strong wells this morning, our CMR/Foster Creek 24-13H-1 and Spears 31-6H-1, which are not only significantly enhancing the play, but also have led to an incremental traction in our company oil volume growth since the end of the third quarter. Looking forward for a moment, we are currently watching the markets very carefully and have a number of development scenarios both offensive and defensive we are capable of executing on next year. This includes, if market conditions and events dictate, maintaining the currently active 3 rigs we are currently running in the TMS, which would result in a hypothetical 2015 CapEx budget in a range of $200 million to $225 million. This is obviously just one of a number of potential development scenarios for next year. But with the reaffirmed borrowing base and sale of the non-core East Texas Cotton Valley properties, both of which we announced this morning, which will provide us ample liquidity, we are confident we could execute a 3 rig TMS plan next year, continue to grow oil production at a meaningful rate, and do so within the means currently available to us. We have tremendous flexibility to execute any one of a number of different activity levels next year. We currently have an excellent staggering of our rig contracts in the TMS, with one rig on a well by well basis, one with a 6-month term contract expiring in March of next year, and a third contract which currently runs to the end of May. Any of these contracts can likely be extended, additional rigs added, if balance sheet and market conditions allow. In addition to the great flexibility we have with the rig contracts, we are also moving towards an increasing percentage of our activity on multi-well pads, as we move from primarily delineation mode into development mode. We are currently drilling our first 2 well pad with our CMS Foster Creek -- excuse me, CMR/Foster Creek 8H-1 and 8H-2 wells looking into 2015 and assuming we stay with a 3 rig program, we project we will drill approximately 21 new TMS wells in 2015, and our current plan will be for approximately 2/3 of those to be drilled on multi-well pads. This will allow us to leverage off of individual well locations and simultaneous drilling and completion activities to drive completed well cost lower in 2015. From the early days in TMS, we have seen a wide variation of well designs, including lateral links, landing targets, interval frac stage links, perf cluster spacing, profit volumes and fluid types. Through approximately 52 industry-wide modern era horizontals and considerable trial and error experimentation, we have gained a tremendous amount of play-specific knowledge, which is now paying dividends, and I believe the industry participants are all generally moving in the same direction towards ultimate best practices. In fact, of the 52 modern-era horizontal wells, 21 have been drilled during this calendar year. As a result, we now have 15 wells we have classified as optimized wells, which have been drilled and completed using criteria that we define as best practice. More on that in just a minute. In an effort to share this insight with you and do so in as transparent a way as possible, we prepared a presentation for you, which has been posted on our website, and Rob and I will spend a few minutes reviewing the data with you. To those of you who have access to the presentation, we suggest that you open it now and please turn to Page 3. On Slide 3, here, you'll see a map of our -- and location of our current core properties. We continue to maintain a balanced portfolio of assets, including a nice balance between our extensive Haynesville Shale gas assets, largely HBP and poised for a better gas market, and our crude oil assets in the Eagle Ford Shale and Tuscaloosa Marine Shale. On Slide 4, you will see the progress we've made growing net crude oil production volumes, including the 15% sequential increase in oil production reported this morning, when comparing the third quarter with the second quarter of this year. In addition, you'll see the significant increase we are projecting for the fourth quarter with our total crude oil production guidance and mid-point of which is 6,000 barrels per day, which is being driven by expanding volumes in the TMS. The reason we proactively hedge our production is for markets like the one we are in currently. And on Slide 5, you will see our crude oil and natural gas hedge position. At the bottom of the first column, you'll find our current oil hedge position for the first quarter -- excuse me, the fourth quarter of 3,800 barrels per day at a blended average price of $93.65 per barrel, which covers almost 2/3 of our mid-point of guidance for the fourth quarter. Above, you will see we have approximately 90% of projected fourth quarter gas hedged at $4.76 per MMBtu. Even more importantly, at the bottom of the 2015 column, you will see we currently have 3,500 barrels a day hedge for all of next year at a blended average price of $96.11 per barrel. If you'll now turn to Slide 6, we have highlighted several hypothetical oil volume production scenarios for next year, and 3 different oil price scenarios with the -- for the percentage of oil production we do not currently have hedged. We encourage you to review this at your leisure, but I will just say that even if the non-hedged wellhead prices average $70 per barrel in 2015, the positive impact of our hedges should result in an average net price of $81 to $85 per barrel under most any outlook for hypothetical 2015 oil production growth. On Slide 9, (sic) [ Slide 7 ] we move to the Tuscaloosa Marine Shale, where you will see the geographic location of the play and some key highlights of the play. As most of you are aware, it's an emerging shale play in southwest Mississippi, southeast Louisiana, covering approximately 2.5 million acres. Goodrich has built an industry-leading position of over 300,000 net acres in the play. It's a very well and increasingly defined play with significant oil saturation and good rock quality in the TMS. The play is found between depths of approximately 10,500 feet and 14,000 feet true vertical depth. And very importantly, sufficient thickness across the play between 100 and 250 feet of TMS thickness. We've been averaging something slightly north of 40 degrees gravity, so we have light sweet crude and the oil volume percentages are very, very high between 92% and 98% oil with very high BTU gas. Let's move to Slide 8. Here, you will find a map, which is beginning to outline and define the emerging core fairway where we have now consistently seen optimized wells exhibiting rates in excess of 1,000 barrels per day. On this map, you'll see 13 wells represented by the red stars, which all have had initial rates in excess of 1,000 barrels per day. In addition, you will see 3 blue stars with initial rates slightly less than 1,000 barrels a day, which were optimal completions or in the case of the Bates 25-24H-1, slightly suboptimal. But it performed quite well, and Rob will review all of these individual wells with you in just a minute. As you can see, we are developing a nice trend with a general east-west elongation and alignment and falling between 11,000 and 14,000 feet. As you can also see, we have a substantial acreage position throughout this trend, whether it's our legacy acreage in yellow or the acreage in orange, which we acquired last year and where Sinopec is our 1/3 partner. As we move towards more development drilling in 2015, virtually all of our current planned activity for next year is along and within this trend, running from eastern Wilkinson County through southern Amite Counties of Mississippi. And into Tangipahoa Parish, Louisiana in the vicinity of our Blades well, where we expect to see a concentration of activity on this very large footprint. Given the wide variety in lateral lengths, frac styles and completions designs, and then carefully analyzing the variable within well production performance, we've identified 15 wells thus far, which met our optimized well design or optimized criteria, which you will see on Slide 9. Our optimized criteria include the following attributes

[Robert C. Turnham:]

Thanks, Gil. The optimized wells that we and our offset operators have been drilling lately are performing very well, not just from an initial rate but over time, and our decline curves show it. The TMS is a geologic formation that not only has very good matrix porosity and permeability when fracked, which gives you hyperbolic curves and long life reserves, but has an added benefit in that the formation has naturally occurring fractures, which enhance hydrocarbon storage, production rates and EURs. As everyone knows, our Crosby well as shown on Slide 10 has been the poster child for the play as it has produced approximately 200,000 barrels of oil in about 20 months, and continues to produce at or above our 800,000 BOE curve. The rate of decline of optimized wells over the time is shallower than what we have seen in other wells, and you see that when you look at the Crosby from month 10 to month 20 in which we only lost about 50 BOE per day. Slide 11 is our CMR 8-5 well, which has been online for approximately 8 months and is tracking our 600,000 BOE curve. The CMR 8-5 met the minimum criteria with a 5,300-foot lateral and 450,000 pounds of proppant per stage. We see the benefit of longer laterals ideally. But with that said, our Blades well on Slide 12 is one of the top outright performers, and certainly a top performer per foot over the first 7 months, as it is currently producing above our 800,000 BOE curve from a 5,000-foot lateral. The Blades area of Tangipahoa and western Washington Parishes comprises about 75,000 net acres, and is where you will likely see a high percentage of our 2015 development, including numerous 2 well pad wells, which will further drive down well cost. If you draw the fairway from our Blades area to the Crosby area, it encompasses approximately half of our 300,000-plus net acres. Our C.H. Lewis is an outstanding well over its first 5.5 to 6 months, as it continues to perform at or above our 800,000-barrel curve. Our Lewis well shares a pad with our Spears well, which we announced on this release at 1,360 BOE per day, 95% of which was oil, on a restricted choke size of 15 64s. We are seeing very significant benefits in being conservative early during flowback under a managed restricted choke program, which minimizes pressure drawdown over time and flattens our curves. Our Nunnery and Bates wells are delineation wells on the north and northeast edges of our block where it is more shallow, approximately 10,500 to 10,800 feet true vertical depth. The Nunnery is in our optimized database as we had more than 5,000 feet of completed lateral, and it was fracked effectively. But the early result appears below our 600,000 BOE curve, likely due to depth and less thickness of high-quality TMS. When analyzing with the Passey method, which overlays porosity with resistivity, we calculate approximately 75 feet versus 100 to 150 feet typically seen across our block. As to our Bates well on Slide 16, we've shown the curve here, but it is not in our optimized data set, in that the lateral is less than 5,000 feet. Both of these wells are on the edge of our block in the play, and we see future development potential for the area once we bring our cost down to the low end of our range of $10 million per well under full development mode. We are very encouraged by our Beech Grove and SLC wells to date as decline curves were initially flatter, which allowed for the intersection and tracking of our 600,000 BOE curve within about 45 days, even though initial rates were lower. As we have previously stated, these wells are deep at approximately 13,500 to 13,800 and appear to have subtle differences in rock properties likely driving the difference compared to our 11,000 to 13,000-foot wells. We're about to kick off artificial lift on the Beech Grove, which we think will be very beneficial for oil rate, and the SLC won't be far behind. We've completed 3 very good wells recently. Our Denkmann well on Slide 19, which is tracking our 700,000 BOE composite curve with plans to put it on artificial lift next week, which will ship improved rates, as well as our CMR 31 and CMR 24 wells on slides 20 and 21, which are early in flowback, but riding at or above our 800,000 BOE curve. We have a non-operated interest in 2 Encana wells that we show on the next 2 slides, both of which are performing extremely well, with one tracking our 700,000-barrel curve and the other one well above our 800,000 barrel curve. And we finish with 2 exceptional non-operated wells in which we do not own an interest. Both wells utilize the optimized completion recipe, and both are tracking north of our 800,000 BOE curve, with one in particular, likely the best well in the field. There's been quite a bit of discussion of late around EUR projections, generated from decline curve analysis with various b factor or curve shape assumptions. Our strategy has always been to be very transparent in tracking daily versus monthly volumes, as it normalizes production for downtime when generating type curves, and is more accurate than state reported data. We are letting the production data drive our curves. We certainly are believers in the fact, that the more history and data you have, the more comfort there is in developing type curves. To that end, when you look at Slide 26, you will see an old vertical well, the Texas Pacific Blades well that was drilled in 1978, and has produced for more than 30 years. Although you can't compare production rates from this well with modern-day simulated wells, it provides a good curve shape and data point on matrix flow from the formation. In this case, the well shows a 2.0 b factor and very low terminal decline rate. What initially changed the play in our mind, however, were the 3 encore acquisition wells shown on Slide 27 that were drilled in 2007 and 2008, and that now produce for 5.5 to 6.5 years. The wells were short laterals with inferior frac designs, but exhibit very good hyperbolic curves. And in fact, the curves get better with time. The 3 wells have an average b factor of approximately 1.46, with the oldest well at 1.55. If you go to Slide 28, you will see the legacy TMS wells we purchased in August of 2013 that were drilled in 2011 and early 2012. Again, not long enough laterals are stimulated optimally, but exhibit very consistent hyperbolic curves with a composite b factor of 1.45, the same as the encore wells. Slide 29 is our optimized composite well decline curve with b-factor sensitivities. As I previously stated, we try our best to tight-fit actual data from daily production early in the life of the wells, and then make type curve estimates based on historical data when possible. As you can see from this slide, our normalized type curve of 700,000 BOE best fits the data. If you utilize a one-part curve with a 1.45 b factor, again, same as the encore and legacy well averages, you see the same rate of return and similar production over the first 24 months, but the production tail is slightly steeper in the outer months, driving the EUR down to 600,000 BOE from the composite curve EUR of 700,000 BOE. We have also shown a 1.3 b factor curve, but as you can see, it does not fit the data. We also showed the economics at a blended average price of $85 per barrel, which as Gil has previously stated, is a hypothetical price per barrel we would generate with our hedges and as low as $70 per barrel NYMEX on our unhedged volumes. Our composite type curve of 700,000 BOE and the 1.45 b factor curve of 600,000 BOE both generate 32% to 46% internal rates of return at $85 per barrel depending on well cost. Again, the 1.3 b factor curve does not fit the data and therefore, the well economics are irrelevant. As Gil pointed out, in a hypothetical 3-rig scenario, as much as 2/3 of our pretents [ph] for capital expenditure budget for 25 -- 2015, could be allocated to 2 well pads where we see clear sight to potential well cost in the 11.5 million range, which we show significant -- where we also show significant oil volume growth year-over-year and live within our means with optimal necessity for external capital. Our last slide on page 30 is an oil price sensitivity graph showing change in rate of return using unhedged pricing of $70 to $100 per barrel. Although not optimum or relevant for us in 2015, since a significant portion of our barrels are hedged at $96, unhedged pricing of $70 oil generates 20% to 27% internal rates of return, whether using our composite well type curve or 1.45 b factor curve, with breakeven at $50 per barrel. Breakeven in this analysis is the price necessary to generate a 10% rate of return. Our TMS wells enjoy significant advantages over other plays, including better price realization at LLS minus 2 at the wellhead, lower royalty burdens of an average 17.4%, and low to no severance tax until payout. Some of the recent commentary on basin breakeven analysis has been wrong, and we can always surmise that they weren't baking in the proper assumptions into their modeling when running the calculation. Our TMS operations are going well and we are in completion phase on our Verberne and Williams wells currently, with back-to-back frac dates scheduled to begin middle of this month. We are drilling the laterals on our true, first true 2 well pad, our CMR 8-1 and 8-2 wells, as well as just getting started on our Kent well in Tangipahoa Parish and our T. Lewis well in the Amite County, Mississippi. Very briefly moving to the quarter, capital expenditures totaled $97.2 million with 78% spend in the TMS, drilling and completing wells, as well as payment for the lease extensions. CapEx for the first 9 months of the year totaled $259.5 million, and we have guided to $60 million to $75 million for the fourth quarter, which would have yearly CapEx at the low end of our $325 million to $375 million budget. Production for the quarter totaled 6.1 Bcfe, or an average of approximately 67 million cubic feet equivalent per day, with oil averaging approximately 4,800 barrels per day, which is 43% of total volumes and 77% of revenues. Since the end of the quarter, we have averaged approximately 6,000 barrels per day, which is midpoint of fourth quarter guidance of 5,700 to 6,300 barrels per day. Fourth quarter guidance has been impacted by timing of pad drilled wells and our frac schedule, which is backend loaded. I'm now going to turn it over to Jan to walk you through the financials.

[Jan L. Schott:]

Thank you, Rob. Good morning, everyone. I will cover a few items on the financial side. Revenues for the third quarter totaled $54.9 million, a decrease of $2.3 million or 4% lower than revenue for the comparable period last year, and $1.6 million or 3% higher than revenue for the second quarter of 2014. Our third quarter average realized prices excluding the impact of realized gains and losses on derivative were $96.22 per barrel for oil, and $3.63 per Mcf for natural gas. Earlier, Gil covered our current hedge position on Page 5 of the presentation. We plan to continue to layer on additional oil derivatives as we increase oil production, and we will also continue to watch natural gas for opportunities to hedge portions of our natural gas production. Moving on to expenses. LOE this quarter was $6.7 million or $1.10 per Mcfe, compared to $1.17 last quarter and $0.92 for the prior year quarter. The third quarter includes $0.6 million or $0.10 for workovers, primarily in the Haynesville Shale. As we have mentioned before, as we increase our oil production, we would expect our LOE rate per unit to gradually increase over time, with oil production representing 43% of total production for the third quarter. DD&A per Mcfe was $5.88 for the quarter, compared to $4.82 last quarter and $4.33 for the prior year quarter with increased oil production. We would expect the overall company DD&A rate to turn slightly higher next quarter as oil production continues to increase as a percentage of total production. G&A costs came in at $8.3 million, $1.36 per Mcfe this quarter, compared to $1.51 last quarter and $1.08 in the prior year quarter. About $0.33 or 24% of the third quarter rate represents noncash stock-based compensation. In the third quarter, we recorded a noncash impairment charge of $85.3 million related to fields in East Texas that we are selling. We are projecting a 0 tax rate for the full year of 2014. We ended the quarter with $2.2 million in cash and $118 million drawn on a revolver. Following the October redetermination in conjunction with our July 1 reserve report, our borrowing base remained at $250 million and the company was in compliance with all financial covenants as of September 30, 2014. Upon closing the sale of our East Texas fields, our borrowing base will be $230 million. The next redetermination of our borrowing base will occur in early 2015 with our year-end reserve report. We have included reconciliations on the last pages of our press release for all non-U.S. GAAP measures to the closest U.S. GAAP measure. Please refer to these reconciliations for more detail. We plan to file our third quarter 2014 10-Q with the SEC this week. Please see our 10-Q for a more detailed financial discussion. With that, I will now turn it back to Gil for some closing comments.

[Walter G. Goodrich:]

Thank you, Jan. As we move from primarily delineation drilling into more development mode, we will increase our focus on bringing down individual well costs from the current range on a single well pad of approximately $13 million to wells in, as Rob highlighted, the $11 million to $12 million range next year, as we leverage off of single locations, skidding the rigs between wells and zipper frac completions. As we have said from the beginning, the cost of an individual well on a single pad was far less important and impactful on the play's resourced economics than the average cost per well in development mode and utilizing multi-well pads. We are excited to be entering this phase of development, and look forward to demonstrating enhanced economics in the play in 2015. That concludes our prepared remarks. I'll turn it back over to the operator for questions.

[Operator:]

[Operator Instructions] Our first question will come from the line of Leo Mariani from RBC.

[Leo P. Mariani:]

I was hoping you can give us a little bit more color, kind of around the hypothetical 2015 range and the 6,000 to 8,000 barrels a day. I know you guys kind of talked about potential for 2 to 3 rigs in the TMS. Is that kind of what gets us to that range with 2 at the lower end and 3 at the high end, and you talked about CapEx $200 million to $250 million? Can you just kind of walk through some of the assumptions in terms of CapEx and reactivity to get us to the low end at 6 versus the high end at 8?

[Walter G. Goodrich:]

Yes, sure, Leo. This is Gil. And again, I'll caution everyone listening that this is hypothetical, we've not set a 2015 budget. We will do that with our board in December, and it's likely to be very fluid given where current oil prices are. So we'll caveat that. And yes, if we pare down, we drop one of the rigs, we get down to 2 rigs, we think we could still grow volumes year-over-year and average somewhere in the ballpark of about 6,000 barrels next year. That would be a more defensive posture in our mind. And then as we stage up, at 3 rigs, we're probably up another 1,000-plus barrels a day, a little over 7,000 barrels a day average and growing volumes. And then 8,000 is probably if we get a little bit more aggressive than that in terms of rig activity. So that's the best kind of ballpark hypothetical we can give at this time.

[Leo P. Mariani:]

Okay, that's helpful here. And I guess in terms of the CapEx range you guys talked about, would that kind of assume the sort of the middle of that range there, the 7,000?

[Walter G. Goodrich:]

Yes. That would be what I've outlined, Leo, which would be $200 million, $225 million, that's kind of what would run 3 rigs for us next year. Remembering that a significant percent of that is likely to have a partner or 2 in the vast majority of the wells.

[Leo P. Mariani:]

Yes. Okay, that's helpful. And I guess, can you guys maybe just talk to a little bit about kind of managing your leasehold? Obviously, you've got a very sizable position here, just in terms of how that activity level would kind of correspond to, I guess, leasehold expiries next year, and sort of plans to manage that longer term?

[Robert C. Turnham:]

Yes, Leo, this is Rob. Good question. Obviously, what we're going to be focusing primarily with our drilling activity is the fairway between the Crosby and the Blades areas. We have a plan that basically allows us to capture the vast majority of what is expiring within that kind of fairway. We're also planning to allocate some dollars to kicking or renewing some leases that should get us to a point where we think we're going to be within our kind of reasonable estimate of where we currently sit, being a 300,000 net acre position. We're starting from 326,000 or 327,000. We've always mentioned it as 300,000 acres plus, but frankly, we have another 27,000 acres on top of that. We'll high-grade the acreage, we'll likely not renew under a draconian situation or extend acres where we're the only player in town, perhaps in the deeper portion of the play where there's less competition, and really focus on between the Blades area and the Crosby areas. A little vague on the answer, but frankly, it's all going to be dependent on our 2015 CapEx budget, which we'll approve in December after our board meeting, and expect to be able to give you a little bit more color at that point in time. But certainly, our goal is to live within our means, which the 3-rig program allows, and that's obviously talking about cash flow plus available liquidity. And yet still maintain as close as possible to our 300,000-acre position.

[Leo P. Mariani:]

That's helpful. And I guess just final question if you could just update us in terms of the JV status? And I guess also the kind of flip side to that question, I would assume though if the JV were to be executed at some point, obviously that could give you guys a little bit more flexibility in your spending plans for next year, so maybe you could just talk to that as well.

[Walter G. Goodrich:]

Sure, Leo. Well, the last part first. This is Gil. Obviously, if we execute on a JV later this year then things could change pretty significantly in terms of the activity levels for next year. In terms of the process. Really, no material update. We're continuing to, as we said on the last call, have conversations with people. They're kind of, I would say, in the latter stages of the technical review, we've not begun the more serious phase of really getting into deal terms or structure at this point. We would expect that to happen, likely with a number of people over the next couple of months, but in our mind it's on schedule, we're still having conversations, and we'll just see how that's been impacted if at all by oil prices, so I think at this time, we're staying very flexible in terms of being prepared to take a very defensive posture next year, or a much more aggressive one. In the terms of the JV, we're on schedule as we expected from a time standpoint.

[Operator:]

And your next question will come from the line of Neal Dingmann from SunTrust.

[Neal Dingmann:]

Say a question, Rob, for you, or Gil, I guess. Just wondering when I look at all these type curves now that you all put in, your thoughts as far as just for some of these wells now that have been on for a few months, how you're perceiving, I mean, I guess, not just looking at if we've got necessarily a 600,000 or 700,000 sort of EUR. But your thoughts as far as how you're seeing those sort of deplete, is that sort of on progress at this point, and your thoughts about -- could some of -- could you reenter some of those and restimulate and potentially push those back up. Your thoughts about those 2 things?

[Robert C. Turnham:]

Yes, Neal, this is Rob. I mean, obviously, extremely pleased with these optimized wells. It's not just us doing it either, certainly in Canada and others are making very good wells also. So it feels like the completion recipe is about right. It doesn't mean you can't slightly tweak it from here to improve further. We've been very pleased with how flat the curve has been. And obviously, as I said in my prepared remarks, we're really tracking the dailies [ph] and accounting for those dailies [ph] in putting out our type curves, whether it's a 1.45 or a 700,000 optimized composite curve, frankly, we'll take either one, because what's most important to us is the return on capital employed. And as you can see, both of those curves generate similar rates of returns. So as far as refracking, we haven't even thought about that. We're dealing with kind of early flow that's very encouraging. We get a lot of the capital back fairly quickly, and feel like we're just getting exactly where we need to be. One question remains. For example, in the Blades area where we've got one of our best wells, is from a 5,000-foot lateral. We think that's because the quality of the rock and the thickness of the TMS that has high quality, is perhaps driving even better well results down there per foot. And we're evaluating whether a 5,000-foot lateral in the Blades area, which is above our 800,000-barrel curve, which is cheaper, because of its shorter lateral, is actually better to drill versus a longer lateral, which we know would have a higher EUR. But the question is, what is its internal rate of return. So the Verberne well, which is an offset for the Blade, it is going to give us a real good data point there. It's about 7,600-foot lateral or 6,700-foot lateral, so it's a good bit longer than the Blades well in the exact same spot. So it might be an opportunity to drill shorter laterals, spend a good bit less money, not just on pad drill wells, but less stages to frac and drive our costs further, even perhaps below the $11.5 million target for 2 well pads.

[Neal Dingmann:]

Okay. And then just a sort of larger question. As far as -- if oil prices continue to have this pressure, just for you, Gil, your thoughts as far as, I guess, the remainder of this year and into next year, your thoughts as far as cutting CapEx, cutting the rig program versus trying to get a JV versus an Eagle Ford or Angelina sale, how you sort of look at all these things on the table?

[Walter G. Goodrich:]

Sure, Neal. Well, as we tried to outline in the remarks this morning, we're very flexible. We're prepared to play significant defense if market conditions dictate that we do that. And with a little bit of improvement in price and our outstanding hedge position, with a JV, we're prepared to play pretty significant offense. I think, really for us, as we tried to outline, even with $70 a barrel, we're going to end up with a pretty nice blended average price, which makes the TMS activity look very attractive to us. So the larger question is just more long-term systemic prices, where do they land, do they stay down in the $70 range throughout 2016 or 2017, then we'll have to start making some adjustments, which we would obviously do during the course of 2015. So like everybody else, we're watching. We'll also see what the corollary does on rig rates and goods and services and completion costs because highly unlikely in our view that we're going to see a $70 -- a range of $70 oil price in 2015 without seeing some pretty good improvement on the cost side. So we'll see how all that stacks up and the reason we hedge is to give us the flexibility to make adjustments gradually instead of knee-jerk type reactions.

[Neal Dingmann:]

Sure. Sure. And then last one, if I could, maybe just for Jan. As far as looking at the borrowing base, it did come down a little bit after the sale, obviously. Just your thoughts, I'm trying to figure out how many and how that will change and how much -- how many TMS wells were included in that. So I guess what I'm asking is, on a net basis, is that going to change? Will you have dramatically more TMS wells included when the redetermination hits early this -- early in '15 or were some of these newer, more recent TMS wells already included in that net revision?

[Jan L. Schott:]

No, they really weren't. The redetermination was based on our July 1 reserve report, which I stated in my comments. And really, some of these newer completions have really come in the back part of the year, so I think we'll get the benefit of that when we do our year-end reserve report. So definitely, I would expect it to go up, we never get in front of our bank group, we kind of say that consistently, but I think we've had really solid results for the last wells that have come online, especially this quarter and then what we're seeing right now too.

[Walter G. Goodrich:]

And, Neal, Jan's answer was perfect. One thing to add really is when you think about it, we were transitioning away from the Eagle Ford with very few completions in the first half of the year. We were delineating the TMS by spreading wells out, which obviously, we had a couple of wells that are on the edge that didn't produce nearly as much cash flow or borrowing base and that's about to change because of drilling in the fairway and adding all these wells that Jan mentions.

[Operator:]

Your next question will come from the line of David Deckelbaum from KeyBanc.

[David Deckelbaum:]

Just kind of following up on what Neal was asking on well costs. Are you in any preliminary discussions with your service providers on kind of lowering those costs, even where we are today? And how does that kind of inform your target for next year, the $11.5 million? Do you -- what sort of increment do you see if we stay in sort of this kind of pricing environment just from pricing coming down?

[Walter G. Goodrich:]

Yes, David, this is Gil. I'd say, the number one issue we probably have the -- perhaps the most wing [ph] to it is the frac cost and what we're playing on frac spreads. That's a huge component in what we're doing in the TMS. Probably a little early at this juncture. We are however, right on the cusp of beginning the process that we go through annually, which is our annual redetermination for the business in 2015. So between now and Christmas, we will have, we will have gone through that process and we anticipate having our frac spread set for, on rate basis, for 2015. So I think it's just a little bit early, probably in this case. It behooves us to be a little bit more cautious on the timing and let oil prices settle out here and see what happens before we lock those in and that's kind of the path we're on.

[David Deckelbaum:]

Okay. And are there any other initiatives in addition to just the multi-well pads that you expect to employ next year to try to further bring these costs down?

[Robert C. Turnham:]

Yes. David, this is Rob. I tried to mention it in my response to Neal with a good bit of our activity in the Blades area, which clearly, when you look at this Passey analysis that we included in our management presentation, clearly it's thick. It's actually thicker than the Crosby area and the quality of the rock is the same, if not better than the Crosby area. So the potential of drilling either shorter laterals or spreading out your frac intervals such that you're fracking fewer stages, and our per-stage cost is obviously a big driver of our completed well cost. That clearly potentially can be a driver for driving our well cost down. On top of that, as we all know, just by drilling 2 well pads, not only do you save some days in between wells, we skid it in about 6 hours versus move the rig in 6 days. But we utilize the same surface, the same facilities, you zipper frac the wells, all of that really automatically in our opinion, amounts to about $1.2 million to $1.5 million per well of savings. And another thing we're looking at also, which we think has real promise is the use of spudder rigs, where you get out ahead of your rig schedule, you use a very cheap rig to drill, to surface casing at about 3,500 feet and you follow it up with the more expensive rigs, so you're really maximizing your dollars per day by using the cheaper rig in the very shallow portion of the play. So those are some things that we're looking at. We really don't want to do anything that might save money but jeopardize our optimal completion recipe, which we're really thrilled with that's working so well. But plenty of ways to drive our well cost down, much less, as Gil said, just service company price pressure.

[David Deckelbaum:]

Got you. And just one more if I might. In this hypothetical scenario, I know that there's a lot of moving pieces right now, but if you had to play defense, does that assume that effectively, every CapEx dollar goes towards the TMS?

[Walter G. Goodrich:]

Yes. We're very fortunate in that the Haynesville, for the most part, is held by production in North Louisiana with very little capital commitment needs in the Angelina River Trend. In fact, we very well could defer some of that. In the Eagle Ford, we have 1 big ranch called the Burns Ranch that's been a very good asset included in our Eagle Ford acreage. It has continuous development provisions that multiple companies can perpetuate and certainly, there's other operators that are helping to perpetuate that if we need that through 2015. So we feel like we have plenty of flexibility to maintain our core Eagle Ford position, as well as our Haynesville position.

[Operator:]

Your next question will come from the line of Brian Corales from Howard Weil.

[Brian M. Corales:]

You talked a lot on the cost side in the savings with the 2 well pad. Can you maybe talk about what the timing, I mean, if the 2 well pad can get more wells per rig per year, I guess what I'm ultimately getting at is the 21 wells, the hypothetical case for next year, is that a gross basis? And could these 2 well pads make that more?

[Walter G. Goodrich:]

Yes, Brian, this is Gil. Good morning. Yes, it is gross. 21 would be gross, and that's obviously just assuming 1 rig can drill 7 gross wells per year, so we've run 3 all year. As I said or alluded to, at least, we would not have 100% working interest in any of those wells and probably, you should figure on something around 2/3 to 70% blended average working interest across the play, which we think is conservative. So -- and then, yes, we don't want to count a chicken until it's hatched, so if we get up on path, [ph] and this is going really fast, and clips out you might drill an additional well per rig per year. And hopefully, if we can do that then we've got lots of flexibility of maybe even having some wells in inventory to be fracked that don’t quite get fracked at the end of the year would spill over into 2016.

[Brian M. Corales:]

Can you maybe talk about your kind of spud to spud rate currently and what that has been, maybe for the third quarter or second quarter?

[Walter G. Goodrich:]

Sure. I don't have the exact numbers in front of me, Brian, but we've been averaging probably something in the 35-day range of spud to total depth. No 2 wells, obviously, being exactly alike. But average has probably been getting pretty close to 35 days. And then it generally takes us 4 to 5 days on top of that to condition the well, get the pipe to bottom and submit it in place, and then we begin the process of cleaning the rig, breaking it down and moving it. That generally is a 7-day process. So I'm not sure what I got up to. But getting in the range of about 50 to 55 days, that rig is moving onto a new location. It's got to rig up, that's probably another 5 days. So you're looking at about 60 days roughly of spud to spud.

[Operator:]

Your next question will come from the line Kim Pacanovsky from Imperial Capital.

[Kim M. Pacanovsky:]

Just taking one well, for example, looking at the Blades curve in your presentation and seeing that it's tracking above 800 BOE and you're at about -- just shy of 7 months of data. And just comparing that to something that one of my peers put out using, I guess, just a couple of months of data, and making some b factor assumptions and coming out with like a 500 MBOE type of curve. I'm wondering, now that you've presented all this data and we're seeing the difference in what the actual data is versus what some of these assumptions were, will there be any attempt to have some kind of a dialogue and correct this piece?

[Walter G. Goodrich:]

Well, Kim, we do our best to be very transparent and open and willing to talk with everyone, and that's frankly why we're not hiding behind any data. We're actually putting more data out in the public domain than just about any other company out there because we feel like it's important for people to see the data and be able to make their own conclusions. But the Blades is a great example of a well that's -- very well could be one of our best wells ever or drilled to date, and yet it's even a shorter lateral. So what we've tried to do is just lay out, for everyone's consumption, what we think, what a couple of different alternative analyses on b factors would look like and then let everyone else make their own decisions as to where those wells are going to be. But certainly, you're at a disadvantage when you're looking at state data. You're at a disadvantage if you don't do the type of detailed analysis and work that we do, analyzing historical data, comparing rock data across the play. And another thing that you can't really do is take one play's decline curve and b factor and compare it to another because rock properties change and they're different across plays, and so each play has to hold its own and that's why we're showing the data and let people analyze it and figure out who's right on these projections.

[Kim M. Pacanovsky:]

Okay. And then one other question. Gil mentioned -- the bigger question here is what long-term oil prices are going to do, and if we're going to be in a $70 environment. And given that, that is a possibility, can you just let us know how you're looking at the hedging market? And everybody is saying, "Well, we wouldn't put hedges in here." But if we really are looking at an extended hedging market, how do you look at where you'd pull the trigger?

[Walter G. Goodrich:]

Kim, this is Gil. I would say this. We're well hedged for 2015. So the question for us is not really adding necessarily a whole lot of volumes. We tried to lay out what we think we would end up on a blended average basis for next year without adding any additional hedges. So I would say that -- simply say that our hedging committee is very, very active looking at the market on a daily basis. I think the bigger question would be for us for 2016, and how does the cost-to-price ratio play out during the first half of next year before we would start to look at adding any hedges. I don't -- my personal belief as one member of the committee is we would not be hedging oil at $76, $77, $78 a barrel and unless and until we saw a 20% to 30% decrease in our costs.

[Kim M. Pacanovsky:]

Right, okay. Fair enough. And have you heard anything updated on some of these Haynesville recompletions from your friends in the play?

[Walter G. Goodrich:]

No. This is Gil also. We are watching that carefully, but we don't think definitively that we could make comment on that at this point, Kim.

[Operator:]

Your next question will come from the line of Mike Kelly from Global Hunter Securities.

[Michael Kelly:]

As it pertains to the JV process, it was my understanding that interested parties were really asked to give you guys an indication of interest by the end of October. Was hoping to get an update on this, if that was the case and to hear what type of feedback you got, just a general sense of interest there too.

[Robert C. Turnham:]

Yes, Mike, this is Rob. Yes, there's no formal process with dates on that. We've really had some interest along the lines of 3 different subgroups, I guess

[Operator:]

Your next question will come from the line of Phillips Johnston from Capital One.

[Phillips Johnston:]

As you look at the performance of the Beech Grove well, obviously the IP rate was far [ph] and you previously talked about a flatter decline profile. But -- yet the curve shows that it's now sort of tracking somewhere between 600 to 700. My question is, does that performance there change your thinking at all on your acreage, sort of in the South, sort of in the East and West Louisiana areas?

[Walter G. Goodrich:]

Yes, Phil, this is Gil. We're certainly very pleased with what we've seen through almost 5 months of production. As Rob said, we've got such an extensive footprint up through Wilkinson, Amite, and Tangipahoa that those wells seem a little more prolific at this point in time. So I think in the Beech Grove and the SLC, kind of in that southwestern area, we're pretty content to just sit back and watch these wells play out for another 5 or 6 months and get a year or so of production history would tell us more about how much development we want to do in that area. I think we really have no wells currently anticipated for right in that immediate area. I think we've got some wells north of there just in the Mississippi plan for next year, but nothing right in the Beech Grove. I think we're -- as I said, we're content to just see how this thing plays out for another 6 or so months.

[Phillips Johnston:]

Okay. And then now just a question for Jan. You're in compliance with all of your financial covenants, but can you talk about where the third quarter shook out just on a net debt-to-EBITDA basis, as defined and calculated by the, I guess, the 4x maximum covenant? And maybe what you project going forward.

[Jan L. Schott:]

We were below our -- I think our covenant is the 4x total debt-to-EBITDAX, we were slightly below that, but don't see a problem going forward with what we have in place with our credit facility and the financial covenants, so...

[Operator:]

Your next question will come from the line of Ron Mills from Johnson Rice.

[Ronald E. Mills:]

Rob, maybe for you on Slide 29 of your presentation. Just looking at that curve, you talked about a 1 CH b factor during your prepared remarks, or maybe in an answer. It looks like there may be more of a two-stage type curve here in terms of a shift in b factors starting in months 5 or 6. Is that just skewed by fewer data points, or do you think that the TMS is looking at more that type of a shape than a pure single stage b factor?

[Walter G. Goodrich:]

Ron, good morning, this is Gil. I'll jump in and take that. I think that's really driven by the phenomenon of the early stage flowback is flowing back up 5.5-inch casing without the benefit of tubing or artificial lift. And we normally are getting tubing in these wells. I think Bob may have mentioned that we wouldn't -- our bias is towards getting tubing in earlier. But all that initial significant decline rate is flowing the wells up 5.5.-inch casing. So we then put tubing in. Now you get to about month 5, we've got tubing in and we've got our artificial lift kicking in, and that's when you see the curve really start to break off and take on a different shape. And what we've been impressed with, and obviously very pleased with is really from about month 8 or 9 through month 20, we've seen a very, very flat profile. These wells performing extremely well on artificial lift. So really, it's trying to tight fit that data. It's very likely that if we begin a process of running tubing upfront initially, you would see a more uniform without the necessity for a little bit of a change there.

[Ronald E. Mills:]

And then how does the practice of utilizing restricted chokes on recent wells also fit into that comment, Gil?

[Walter G. Goodrich:]

I would say not a material impact, Ron. The Crosby was never what I would consider any aggressive choke program. We've taken a little bit of a notch down from that just trying to maintain maximum pressure. So I think you could still be looking at 1,000-plus barrel a day initial wells, even restricted as the ones we announced this morning were. And maybe see a little bit of flattening. And I think tubing would help as well, so you wouldn't see quite as much DI or initial decline in the wells and would shape up a little bit more fluidly with month 20 to month 1. Yes, and that's a good point. And if you look on Slide 25, it's a non-operated well, but that's one that would probably be a pretty good example of what I'm talking about.

[Ronald E. Mills:]

And in that one they ran tubing earlier, is that what you're saying?

[Walter G. Goodrich:]

Yes.

[Ronald E. Mills:]

Great. And then on the -- you talked about the Tangipahoa acreage as about 75,000 acres, and with the Passey method, it looks like better-looking rock quality and thicker. If you apply that same, or have you applied that across, even if you just focus on your 150,000 "core acres," do you have other localized areas that look like that Tangipahoa area, or is it just -- is that half of that core just looking that much better?

[Walter G. Goodrich:]

Yes. Well, let me assure everyone that we've applied that method across every acre we have across this play where the data is available to us. And I would only say that in that area, it's not that the porosity readings are significantly higher. We are seeing slightly higher microsecond readings per sonic log. It's just it's a little bit thicker and the performance of the Blades, as Kim pointed out, is pretty outstanding. So we'll just have to wait and see. We don't see anything geologically, Ron, that makes that uniquely different from most of the rest of the play.

[Ronald E. Mills:]

Okay. And then -- so you talked about -- and Rob, I can't remember who, about the fourth quarter timing, it sounds like there were some pushing out of frac dates and leading to the completions being backend loaded in the fourth quarter. If you assume that the 3 rig, the 3-rig program next year and especially with the shift to more 2 well, 2 to 3 well pads, I guess focusing more on 2 wells, how would the pace of completions kind of run as we look through 2015?

[Walter G. Goodrich:]

Yes, Ron, it's a bit of a wildcard because it's going to be contingent upon when and where we drill our 2 well pads. There's obviously a lag time there. In fact, for the fourth quarter of this year, we're being affected by just a bit of a delay on getting a couple of wells fracked, our Verberne and Williams, but we're also being impacted by the CMR 8-1 and 8-2 being a 2 well pad. So we'll try to give a little bit better color after our December meeting. I think the only way we can do it is just to assume 60% of the wells drilled next year are 2 well pads. You probably would have 1 rig drilling single wells and 2 rigs drilling 2 well pads, and maybe call it 2/3 of the capitals drilling 2 well pads. And then just stagger those from a modeling standpoint. So I think that's the way I would look at is 2 of the rigs drill 2 well pads and one of the rig drills one-off wells and model that throughout the year evenly.

[Ronald E. Mills:]

Great. And then one -- just last question, just on the East Texas sale. Any description of the buyer public versus private and/or, I assume the fourth quarter gas guidance assumes the disposition of that production on December 22. Just curious, [indiscernible] production.

[Walter G. Goodrich:]

Yes. No that's right. We've factored in the December 22 estimated close and the buyer is a private company.

[Operator:]

Your next question will come from the line of Mike Scialla from Stifel.

[Michael S. Scialla:]

A question on, if you do end up with this 3 rig case for next year, drill about 21 gross wells. Any of those plan to be delineation wells, or you're just going to stick with the core area at this point?

[Walter G. Goodrich:]

Yes. Mike, we're just going to pound away within the fairway, good bit of activity near the Blades, good bit of activity near the Crosby, and a few wells in between. So no, predictability, consistency of results should be there and the real emphasis is going to be driving well costs down in that we know for the most part, or can expect what the well results have a high probability of being.

[Michael S. Scialla:]

Okay. And in terms of the well cost, you talked about it a lot. But your one well case, with $13 million. How much -- I know you don't want to get into specific wells, but how much variability are you seeing around that now with your recent wells? Is the $13 million kind of a best case scenario, or have you been able to beat that at all in any of these new wells?

[Walter G. Goodrich:]

Yes. You're right, we don't get into individual well costs one well to another. But certainly getting -- zeroing in around those numbers, around that number and our Spears well is a great example, longer lateral, which means you have added completion costs but we were able to drill it a little bit quicker. Now we certainly have some shared costs on the facility even though we didn't get the full benefit of a pad because we had already moved off and we had already fracked the other well. But we're starting to see some above and below, but zeroing in and around the $13 million wells. The drilling is all -- a good bit of that is about the drilling. And as Gil said, starting to average kind of better drill rates. Our well costs on the completion side are stable and we'll see if we can drive those costs down if oil prices remain low.

[Michael S. Scialla:]

Okay. And then on the Spears, my information might have been incorrect, but I thought that was going to be a 7,600-foot lateral. And it sounded like you've got 6,200 feet completed. Was there an issue with part of the lateral there?

[Walter G. Goodrich:]

Yes, Mike, good catch. We drilled the 7,600 but we got a little bit out of our comfort zone on our target window on a portion of that lateral and just out of extreme caution, we said -- we decided to not frac that interval. So just felt like it was more conservative to do what we did and take the 6,200 feet.

[Michael S. Scialla:]

Okay. And then just last one for me. I look at -- what looks like you've defined it as the fairway now. It looks like part of Saint Helena Parish would fit in there, but you haven't really drilled anything in there. Is there anything geologically that prevents you from testing that acreage, or is that part of the fairway?

[Walter G. Goodrich:]

No. We do have plans. In fact there are a couple of others, I think Comstock had some acreage in that area with plans to drill. A private entity here in Houston has some acreage that they're planning to drill in March. We just haven't gotten around to it yet. It's, in fact, kind of east of the Weyeraeuser wells that we had acquired and kind of south of the Encana Mathis, all of that is in a really good spot. And you'll see us put some wells on there. That could be one of those wells that we talked about in between the Crosby and the Blades.

[Operator:]

Your next question will come from the line of Steve Berman from Canaccord.

[Stephen F. Berman:]

Just one question left. A couple -- I guess lost in the oil selloff has been natural gas prices have held in very nicely and seems to be moving up again. The Haynesville has been mentioned a few times, Gil. I'm just wondering, your current thoughts, especially if you don't do a TMS JV on possible Haynesville monetization here to enhance liquidity.

[Walter G. Goodrich:]

Yes, Steve, we're very happy, as board members and significant shareholders holding onto our Haynesville assets. We like the balance, we like the long-term value that we see coming from those assets reemerging and I don't think it's currently in the cards, at least, that we will be selling any of our Haynesville assets.

[Operator:]

And your next question will come from the line of Joe Allman from JPMorgan.

[Joseph D. Allman:]

Just on the issue of liquidity. Could you just talk about the scenarios that you ran? And I see the scenarios in your presentation. And, under worst-case scenario, how tight does the liquidity get and how much is still available on the scenarios? And I've got some follow-ups.

[Walter G. Goodrich:]

Yes, Joe, this is Gil, I'll take that and again, I'm cautioning you and everyone else, these are hypothetical numbers, so take them as a ballpark with a grain of salt. But basically, if we run that 3-rig scenario, we think we would be in a range, obviously, as I said, of $200 million to $225 million of CapEx. It would be heavily weighted towards the TMS. There would be a little bit of acreage land allocation in that budget. We think that at, call it $85 per barrel on a blended average basis, you would see us generating EBITDAX in the range, again, ballpark of $175 million of EBITDAX next year. DCF would be obviously a little bit below that. So call it the range of $125 million to $150 million all in, in that range would be a pretty good ballpark guess.

[Joseph D. Allman:]

Okay. And Gil, so the $85 blended, is that -- if I look at Slide 6, is that using the $70 WCI price?

[Walter G. Goodrich:]

Well, yes, basically, which I think hopefully will do better than that obviously, Joe. But yes, if you just took it all the way down to $70, then that's what you would look like.

[Joseph D. Allman:]

Okay. As of right now, you're -- I know it's alternative and haven't finalized but as of right now, your $200 million to $225 million budget. What are you basing that on at this point? What WTI price are you basing that on? And what's the [indiscernible] gas price?

[Walter G. Goodrich:]

In our budget?

[Joseph D. Allman:]

Yes.

[Walter G. Goodrich:]

We don't have a budget, it's a hypothetical. But it's about $80 and $3.75, I believe.

[Joseph D. Allman:]

Okay. And just how comfortable are you with like, how much -- what's the minimum amount of liquidity that you are comfortable with before you actually make a fairly dramatic change or whatever change you need to make to maintain a certain cushion? What's the cushion that you want to maintain?

[Walter G. Goodrich:]

Well, we've always said that we like to keep our revolver at about 50% drawn. And any time we get much above 50% drawn on the revolver, you're likely to see us taking a step, as we announced this morning, to bring in some incremental capital to reduce that down below 50%. So I don't think you'll see us running at 80%, 90% utilization next year. That's pretty much a given. So everything is fluid, every day is changing. We don't set budgets and then go running down the train track running for a catastrophe. So if market conditions dictate, we'll slow down and cut that CapEx. If they're more favorable, we'll speed up. So there's no way to sit here this morning and give anyone an absolute hard and fast budget for next year. But I would say, if we see us getting up much above 50% drawn utilization, then we're going to be proactive to sell off another asset or bring in some incremental capital.

[Joseph D. Allman:]

Got you. And in terms of that, Gil, so what's most likely? So JV process, you're scoring [ph] that. I mean, is that a likely scenario here? And then what are the other options? You just said that Haynesville, unlikely; how about Eagle Ford? How about other assets? Could you just run through the possible asset monetizations?

[Walter G. Goodrich:]

Well, Joe, we've been through them many times, so I'll do it again. Yes, we're running a JV process, we completed an asset sale today. I was just asked about the gas assets. I think we prefer to hold on to our Haynesville shale gas assets. We may ultimately decide to shift some capital that way if the oil to gas markets dictate that. Yet, if we want to put all of our oil-directed capital into the TMS, certainly, then the TMS could -- excuse me, the Eagle Ford could become an asset we might want to divest ourselves of. All hypotheticals.

[Robert C. Turnham:]

Joe, this is Rob. Let me add one thing. Our best hedge against low oil prices is to slow down. And we're talking about 3-rig program, we can just as easily do a 2-rig program to cut that delta between CapEx and cash flow even further. Before doing something, we all agree, we like to have a gas optionality story as well. And you don't want to sell the Eagle Ford until oil prices have stabilized and improved. And if that's the case, everything else is in good shape.

[Joseph D. Allman:]

That's very helpful. And then just 2 other quick ones. In terms -- like accounts payable, I noticed that in the second quarter 10-Q, accounts payable bumped up from where it was at year end. And so could you give us what that number was at the third quarter and then just describe that bump-up, if you could.

[Jan L. Schott:]

That will all be in our 10-Q that will be filed this week, and a lot of that's just due to timing of payments. So, I mean, you can go back and look historical, and the trend pretty much is the same.

[Joseph D. Allman:]

Okay, that's helpful, Jan. And then lastly, acreage exploration, I know you addressed it earlier. So what are you absolutely going to hold, I mean, in terms of the, out of the say 326,000 to 327,000 what are you absolutely going to hold on to? And what amount might you actually let go?

[Robert C. Turnham:]

Joe, this is Rob. I tried to address that earlier in a broad answer. It is all dependent on what our CapEx budget in December is, and then what we allocate to renewals and where we take those leases. So our goal would be to maintain as much as 300,000 net acres by holding acreage through the drill bit and by lease renewals within our $225 million budget. But until we get to December and actually lay it out, we won't know kind of where that is. In certain areas, we're going to be the only game in town and we'll have more leverage to lower price per acre. And our primary focus is focusing on capturing acreage within the fairway where we're making these better wells and we have every capability of doing that.

[Operator:]

And your final question will come from the line of Jeff Grampp from Northland Capital Markets.

[Jeffrey Grampp:]

Pretty much all my questions have been asked and answered. So only final kind of housekeeping one I have is, if you guys are willing and able to disclose the production from the Cotton Valley asset that you guys sold today?

[Walter G. Goodrich:]

We've been guiding to about 11 million a day equivalent, and that's about 25% NGLs. I've seen some commentary out there at about 5,500, 5,600 per flowing M [ph], and that's about accurate.

[Operator:]

And at this time, I'd like to turn the call back over to Mr. Gil Goodrich for your closing remarks.

[Walter G. Goodrich:]

Thank you very much. Thank you, everyone, for your participation this morning. We look forward to talking to you again on the first of next year with our fourth quarter earnings.

[Operator:]

And ladies and gentlemen, this concludes your presentation. You may now disconnect and enjoy your day.