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Goodrich Petroleum (NYSE:GDP)

Q3 2012 Earnings Call

November 07, 2012 11:00 am ET

Executives

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director

Jan L. Schott - Chief Financial Officer and Senior Vice President

Analysts

Michael Kelly - Global Hunter Securities, LLC, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

William B. D. Butler - Stephens Inc., Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Steven Karpel - Crédit Suisse AG, Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 Goodrich Petroleum Corp. Earnings Conference Call. My name is Tony, and I will be your coordinator for today. [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, Mr. Gil Goodrich, Vice Chairman and CEO. Please proceed, sir.

Walter G. Goodrich

Good morning, everyone, and welcome to our third quarter earnings conference call. With me on the call this morning is Pat Malloy, the company's Chairman of the Board; Robert Turnham, our President and Chief Operating Officer; Mark Ferchau, Executive Vice President, Engineering and Operations; and Jan Schott, Senior Vice President and Chief Financial Officer.

It's our practice to tell you that questions that we may give answers to and comments that we may make may be considered forward-looking statements, which involve risks and uncertainties, and we have detailed those for you in our SEC filings.

Growth in crude oil volumes, which grew by 15% sequentially, from 18% to 23% of total production on an Mcfe basis, versus the second quarter, resulted in both an increase in quarterly EBITDAX to $48 million and a further expansion of our operating cash margin, which increased to just over $6 per Mcf equivalent on adjusted revenue of $8.34 per Mcfe in the quarter.

At the end of the third quarter, we completed the previously announced non-core Cotton Valley asset sale in East Texas for approximately $95 million. After giving effect to the sale of the South Henderson property, as well as a reduction in the natural gas price forecast used by our senior bank group, the borrowing base under our senior credit facility has been affirmed at $210 million, giving us a total of unused borrowings plus cash on hand, or total liquidity, of approximately $113 million as we enter the fourth quarter. The closing of the divestiture of the South Henderson field provides a meaningful boost to our liquidity, and we will consider additional non-core asset sales and/or joint ventures in the Tuscaloosa Marine Shale or Pearsall Shale at the appropriate time to ensure we maintain ample liquidity and can again execute an aggressive oil-directed drilling program in 2013.

Given the recent relative improvement in natural gas prices, with current strip prices for 2013 just under $4 per Mcf, as well as discussions with our joint venture partner in the Haynesville Shale, we now plan to complete and frac approximately 13 gross or 11 net Haynesville Shale wells previously drilled but not yet completed. We expect these will -- wells will be completed during the first half of 2013, with all wells expected to be online and producing by the third quarter of next year. We estimate net capital expenditures of approximately $22 million to complete these wells. And if we use a $4 flat price assumption for 2013, we expect production from these wells will generate approximately $22 million in gross revenue during the calendar year 2013.

In the Eagle Ford Shale play, our drilling team achieved a marked and meaningful improvement in our average Eagle Ford wells drill time performance. Through refined drilling techniques, our team achieved a reduction in the average drilled-to-total-depth time of approximately 40%, or an average of 11 days, for our most recent Eagle Ford Shale wells. These are outstanding results. We congratulate our team. And the end result will be lower cost per well and an acceleration of wells drilled per rig and our modeling cycle times for 2013.

Our pad drilling strategy is ongoing, and while daily volumes remained somewhat lumpy when looked at on a quarterly basis, we are again projecting a further increase in crude oil production in the fourth quarter of approximately 20% over the third quarter of this year.

While we previously expected to rotate 1 Eagle Ford rig to the Tuscaloosa Marine Shale during the fourth quarter, we now plan to maintain 2 rigs running in the Eagle Ford into and through 2013. In addition, following the recent success of 2 new Pearsall Shale wells by other operators offsetting our approximate 10,000-net-acre Pearsall position, we are preliminarily planning our first 100%-owned Pearsall Shale test in the first quarter of 2013.

In the Tuscaloosa Marine Shale, where we have acquired approximately 134,000 net acres, we continue to make progress in de-risking and delineating the play. The drilling issues associated with this play and, therefore, higher well cost experienced to date have primarily been associated with wellbore stability issues or a well-defined, highly, naturally fractured geologic interval of approximately 10 feet within the TMS has had a tendency to slough or cave in to the lateral wellbore, especially when this wellbore is traversed at a high angle. There are a number of potential remedies, including: one, traversing the interval at a lower or a more vertical angle; two, drilling through the naturally fractured zone and setting intermediate casing over the interval; or three, landing the horizontal lateral above the fractured interval.

Our non-operated Ash 31H well has recently been drilled and successfully landed above the natural fractured interval. The well was drilled with a lateral length of approximately 6,600 feet through the TMS without significant drilling-related issues. Production casing has been set, and the well is now waiting on completion. Eliminating the wellbore stability issues and drilling issues, as it appears we have done on the Ash 31H, will result in meaningfully lower completed well costs in the TMS, and we are encouraged by these wells' drilling performance.

On the performance side, we remain very encouraged with well performance to date, with the oldest grassroots TMS completion now having been online and producing just over 11 months and 2 longer laterals having produced just over 5 months, including the Anderson 17H, in which we have a 7% working interest, which is producing over 300 barrels a day after 5 months online. We are continuing our development of the TMS at a measured pace, with approximately $14 million of net capital expenditures invested in the first 9 months of this year, or approximately 8% of total drilling and development CapEx through the third quarter. Production for these wells will begin to impact net oil volumes in the fourth quarter and as we enter 2013.

In addition, we are expecting an additional 4 to 5 Tuscaloosa Marine Shales to be completed over the next 2 to 3 months, which will provide important incremental data points and help with our evolving knowledge and evaluation of the play.

And with that, I'll turn it over to Rob Turnham.

Robert C. Turnham

Thanks. As Gil has stated, we closed the sale of our South Henderson field during the quarter for $95 million, with an effective date of July 1. The sale of this small acreage block and non-core Cotton Valley asset plugs the hole in our CapEx budget for 2012 and provides additional liquidity in 2013. Our metrics on the transaction at the effective date were approximately $2.50 per Mcf equivalent of proved reserves and $8,000 per flowing Mcf equivalent.

Focusing on results for the quarter. Production was 8.3 Bcf equivalent, with liquids of 4,600 barrels per day, comprised of 3,200 barrels of oil and 1,400 barrels of natural gas liquids. Liquids production comprised 33% of total production and 71% of revenues. Our oil price realization for the quarter was approximately $5.65 per barrel over average NYMEX prices. We are currently receiving an approximate $9 premium to NYMEX and, by the end of the quarter, expect to receive LLS minus $7.35 in the Eagle Ford, or over $100 per barrel based on current LLS pricing. In the Tuscaloosa Marine Shale play, we are currently receiving approximately LLS minus $2, or $106 per barrel.

We currently have 2 rigs running in the Eagle Ford and expect that to continue throughout 2013. As Gil mentioned earlier, due to improved drilling efficiencies and the efforts of our technical staff, we are currently seeing a sharp reduction in drilling days and costs associated with our wells, which will lead to more wells drilled in the fourth quarter and through 2013 for less cost per well. By virtue of the faster cycle times, we are now on pace to drill 32 gross, 21 net wells for the year, up from 28 gross, 19 wells previously forecasted. With that said, we are likely going to be able to only complete 26 gross, 17 net wells by the end of the year, down by 2 net wells versus our forecast due to timing delays associated with pad drilling. We now expect to have 9 gross, 6 net wells drilled and waiting on completion as we exit the year.

Guidance continues to be affected by completion timing from pad drilled wells and interferes with the existing wells when frac-ing in certain areas. We typically shut offset wells in during the fracs and gradually see production return to its previous level. Fourth quarter guidance is to average 3,600 to 4,200 barrels per day from 8 gross, 5 net well completions. Completion schedule currently has 3 wells frac-ed in October, 4 in mid-to-late November and 1 at the end of December, with no production adds from that well until 2013.

Our revised exit rate is approximately 4,500 barrels per day, with the difference from the previous exit rate of 5,000 barrels per day coming from the loss of volumes from the South Henderson sale, which was approximately 200 barrels per day, and the delay of completions on 2 TMS wells, the Crosby and Ash wells, which are now expected to be completed early first quarter of 2013.

Our capital expenditures for the quarter totaled $57.8 million, down 22% from the previous quarter, with $51.3 million spent on drilling and completion costs, $3.3 million on leasehold acquisitions, $1.8 million on facility costs and $1.4 million of miscellaneous expenditures.

For the quarter, we spent 77%, or $44.3 million, of our capital in the Eagle Ford, where we have 2 rigs running; and 19%, or $10.9 million, in the Tuscaloosa, with a combination of drilling and completion expenditures associated with 2 non-operated wells and 1 operated well of $9.5 million and leasehold acquisition of $1.4 million.

For the 9 months of 2012, we have spent approximately $14 million on drilling and completion expenditures in the TMS, or 8% of the total drilling CapEx budget. We will release our 23rd CapEx budget in December, but we are likely to continue with the 2-rig program in the Eagle Ford and 1 rig in the Tuscaloosa for the first quarter of 2013, with a decision at that time on whether to bring in a partner and accelerate development in the play.

We continue to hold all of our natural gas acreage and approximately 7 Tcf of resource potential, with very little CapEx for the year. All of our North Louisiana acreage and East Texas acreage is either held by production or subject to lease extensions, which gives us great flexibility on allocation of capital to the highest rate of return projects while maintaining the huge leverage we have to an improving natural gas market.

In the Eagle Ford Shale trend, we conducted drilling operations on 10 gross, 7 net wells and added 6 gross, 4 net wells to production for the quarter. In addition to the Eagle Ford and our secondary target in the area of the Buda, we are in preliminary stages of planning to drill a Pearsall Shale well in our acreage in the first quarter of 2013, near our offset wells that reported initial rates of 1,400 to 1,800 barrels of oil equivalent per day, comprised of an estimated 75% liquids from approximately 10 to 11 frac stages over 3,000- to 3,500-foot laterals. Both wells appear to have similar oil rates of 700 barrels per day to go with very high BTU gas, which will yield a high concentration of natural gas liquids. Obviously, the Pearsall play is in early-stage development, but we are encouraged by the offset well results. And we'll be closely monitoring these and other Pearsall results over the next few months. We have approximately 10,000 net acres prospected for potential development in the Pearsall.

In the Tuscaloosa Marine Shale trend, we have successfully frac-ed 12 stages over an approximate 4,000-foot lateral on the Denkmann 33 #1 well, our first operated well in the field, in which we own a 75% interest. Flowback has been delayed due to the necessity to repair 1 popped casing connection near the last set of perforations on the last frac stage, which stage was successfully pumped. Other than the 1 popped casing connection, the casing is in good shape, with no anticipated issues to reaching our target rate of production once we patch the connection. This is obviously not a typical occurrence, but we've experienced this before in a different area and are confident we will get it patched in a short time frame, at which time, we will then drill out the plugs, run tubing and commit flowback, with production results expected in a few weeks.

We've also participated for a non-operated interest in the Joe Jackson 4H #2 well for 25% interest, which is currently flowing back, and the Ash 31 #1 well for a 19% interest, which is being drilled and is -- which has been drilled and is in completion phase. Although the Ash 31 #1 won't be completed until the Ash 31 #2 well is drilled from the same pad. As Gil described, we were very pleased with how the Ash 31 #1 well drilled, which should materially reduce well costs going forward.

We are currently drilling our Crosby 12 #1 well in Wilkinson County, where we own a 50% working interest. We have drilled, cored and logged the vertical portion of the well and are in the process of kicking off to drill a projected lateral of approximately 7,000 feet. We expect to run an additional 100 feet of casing to get the rubble zone behind pipe in the Crosby well. We have identified 14 potential units that could be drilled in 2013, pending continued success in the TMS, with the Huff 10 #1 well in Amite County, Mississippi, our next operating well after the Crosby. We plan to continue to run 1 rig in the play through the first quarter of next year, at which time, we'll make a decision on whether to accelerate development and bring in a partner.

As Gil stated in the Haynesville Shale, we now expect to participate with our partner in North Louisiana in the completion of 12 gross, 5 net wells in the Bethany Longstreet field, along with 1 gross and net well in the Angelina River Trend, for an approximate CapEx of $22 million. We anticipate this will cause our natural gas volumes to grow by approximately 10% year-end '12 to year-end '13 exit rates.

In closing, the Eagle Ford will continue to drive our oil volume growth through 2013, with an improving gas environment and tremendous optionality on the TMS. Our improved efficiency in reducing drill times and well costs in the Eagle Ford is consistent with every other play we've been in, whether it was the Haynesville Shale or Cotton Valley before that, and we are confident the same will occur in the TMS. And, in fact, the Ash 31 #1 is an initial step in that direction. We remain encouraged in the resource potential of the TMS and our ability, along with the other companies in the play, to reduce well costs. And as a reminder, the TMS enjoys some inherent advantages to other oil plays, and that it is 94% Louisiana Light Sweet oil, with lower royalty burdens and favorable severance tax structure. Although we continue to only allocate a small portion of our CapEx budget to the TMS, the upside remains tremendous for the company, if proven up over the next 6 months.

With that, I would like to turn it over to Jan Schott 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.

Revenue for the quarter totaled $46 million. If you include the realized gains on derivatives of $18.8 million with our reported revenue, adjusted revenue for the quarter was $64.8 million, an increase of $1 million, or 2%, over adjusted revenue for the comparable period last year of $63.8 million and $2.1 million, or 3%, over the adjusted revenue for last quarter, at $62.7 million.

Our third quarter average realized prices, excluding the impact of realized gains on derivatives, were $97.43 per barrel for oil and $2.87 per Mcf for gas. If you include the impact of the realized gains on derivatives, the average sales prices were $105.63 per barrel for oil and $5.60 per Mcf for gas. This represents an $8.20 per barrel uplift in the price for oil and $2.73 per Mcf uplift in the price for natural gas. Our plan is to continue to layer on additional oil derivatives as we increase oil production. We also continue to watch natural gas for an opportunistic time to hedge portions of our 2013 production. Please see our website for an updated slide on our current derivatives position.

Moving on to expenses. LOE per Mcfe this quarter hit the midpoint of guidance, at $0.80, and was also in line with the prior quarter rates. The third quarter includes about $0.05 for workovers. If you exclude workover costs, our LOE rate would have been $0.75 for the third quarter. The LOE rate was $0.86 year-to-date, and if you exclude $0.14 for workover activity, the LOE rates would have been $0.72. As we have stated before, as we increase our oil production, we would expect our LOE rate to gradually increase over time.

DD&A per Mcfe was $4.80 for the quarter compared to $4.17 last quarter and $3.49 for the prior year quarter. The higher DD&A rate compared to last quarter is related to more oil production from the Eagle Ford Shale, which carries a higher F&D cost than our gas properties. We expect this trend to continue in the fourth quarter as we increase oil production as a percentage of total production, coupled with the sale of South Henderson, which carried a much lower DD&A rate. We would expect the fourth quarter rate to increase by approximately 10% over the rate this quarter.

G&A costs per Mcfe came in at $0.92 this quarter compared to $0.81 last quarter. About $0.22, or 24%, represents noncash stock-based compensation compared to $0.18 and 22% last quarter. As Rob and Gil mentioned, the sale of our South Henderson field closed on September 28 and resulted in the gain of $44.2 million for the quarter. Note that South Henderson property contributed 9,600 Mcf per day of natural gas and 200 barrels per day of oil to the third quarter production. South Henderson contributed about 600 barrels per day to our total liquids production, as reported in our press release.

We are continuing to project a 0 tax rate for the full year.

As Gil mentioned earlier, our bank group approved a borrowing base of $210 million in conjunction with their review of our mid-year reserve report. This new borrowing base reflects the sale of our South Henderson property. At the end of the quarter, we had $99 million drawn under our senior credit facility and $1.6 million in cash, for a total of $113 million of liquidity. The next redetermination of our borrowing base will occur in early 2013 in conjunction with our year-end reserve report.

We have included reconciliations on the last pages of our press release for all non-GAAP measures to the closest GAAP measure. Please refer to these reconciliations for more detail. We plan to file our third quarter 2012 10-Q with the SEC later today. 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 I said, we remain encouraged by the performance of the initial wells in the Tuscaloosa Marine Shale and are confident we are moving quickly towards resolving the early time drilling issues. And we believe the next 6 months will be very important in demonstrating the plays' economic potential. Our pace of development in the TMS will be dictated by results in the field. And as we continue with the prudent de-risking of the play, we will continue with our execution of oil-directed drilling and oil volume production growth in the Eagle Ford Shale.

With that, I will turn it back over to the operator for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Mike Kelly of Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Hoping to get some more color on the sloughing issue. After you've successfully drilled this Ash well, do you feel like you've kind of nipped this issue in the bud or is it too early to tell? And then I was hoping you could quantify what the decreased well costs really means? When you say that going forward, if this Ash-type completion is really kind of a new standard, what does that mean?

Walter G. Goodrich

Yes, Mike, this is Gil. I would say that I'm not sure we would classify it as nipping it in the bud. But as we said, we're certainly very encouraged by that, and it is one of the clear remedies for the sloughing off or caving in problem from this naturally fractured zone. As Rob mentioned in the call, on the Crosby, we currently plan to try another alternative, which is to get through it at a little bit more vertical angle, get it off -- get it behind casing and continue with our landing of the lateral down in the bottom, 15 to 20 feet of the TMS. So I think right now, we're going to look at it a couple of different ways. We'll see what impact, if at all, there is on the performance of the wells. And I think either one of them is a very viable option. It really does not, either one, do too much to the overall well cost. In terms of cost, we've talked about a number of $12 million to $13 million. The drilling-related issues, as we look not just at our experiences as an operator but the other companies, have obviously been all over the map in terms of how much time and effort is spent having to ream the wellbores out. Surge laid out the incremental cuttings that are sloughing off into the wells. So that's really all over the map, but clearly, you've heard numbers of $14 million, $15 million, $16 million of total well cost. And we think that by eliminating the sloughing, you can certainly get it back down in the range of certainly $12 million. Of course, that's dependent on lateral length. That would be for about a 7,500-foot lateral, with something on the order of about 25 stages. So shorter lateral, shorter frac stages, obviously, you could drive the cost down lower than that.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. I appreciate that color. Definitely, cost is a hot topic with the TMS. And just to clarify that, $12 million is really what you think you could drill that 7,500-foot lateral today? And going maybe a year out here, as you progress in the play, some operators have said that they need to get well cost down to $10 million a well to see this play really viable. Just wanted to get your thoughts if you agree with that. Or do you even think that pushing them down another 20% plus is possible?

Walter G. Goodrich

Yes, I would say that we certainly see a pathway towards getting cost down to $10 million. It would include pad drilling and leveraging off of that. It would require some incremental infrastructure to come into that part of the world. And the second part of that question is really we're all wondering around where the EURs land. We have not published the range of EURs yet. But I think if you certainly get anywhere near what EnCana has been talking about, it will stand up very robustly even at $12 million to $13 million. So we're not ready to publish EURs, but, clearly, that's the big driver, and the economics of the play is where the EUR is going to land. And we certainly think 500,000 to 600,000 barrels could clearly stand up easily to $12 million to $13 million.

Robert C. Turnham

And Mike, this is Rob. I might add another cost obviously comes from the frac costs, and we've already seen improvement from original frac bids to current. So a combination of reduce the drill days and better efficiencies, more equipment in the market and continuing reduction in frac costs are really the primary drivers.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. Great. And one more, if I can sneak in here. I'll jump back. You mentioned a couple of times in the prepared remarks that you'd be contemplating JVs in both the Pearsall and the TMS,. I think you pegged TMS JV at the end of Q1 possibly after you've really assessed how the play has been going so far. Just hoping you'd give a little more color on that, if you actually have started the process there on the JV side on either basin.

Walter G. Goodrich

Yes, this is Gil. We have not started the process on either one, and we're giving our best guess as to when we think those plays would be in a mature enough place to extract the kind of value we would be looking for in terms of a joint venture. So those are just estimates. It really will depend on the evolution of the 2 plays and where we are. But we certainly think somewhere in the first half of next year, if not roughly around the end of the first quarter, we feel like it seems to be optimal.

Operator

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

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Rob, you mentioned in the prepared remarks on the Eagle Ford the price improvement in terms of where you are today versus LLS and where you're going to at year-end. Do you want to enter into a new marketing or transportation agreement? Or what's driving that?

Walter G. Goodrich

We have. We've entered into a marketing agreement with BP. It's initially getting better pricing via trucks, but we're expecting before the end of this quarter to be piping or transporting via pipeline all of our Eagle Ford volumes. And that's when it's going to kick in at the LLS pricing, less $7.35. That's the NuStar pipeline that we've talked about before, and we're getting close on that. But either way, with the Brent to TI spread widening, our differential or premium to NYMEX has been increasing and, as I said, currently getting to $9 premium as we sit here right now.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And to move over to the Denkmann, Rob, I think you said that you still think you can achieve your anticipated production rates despite having 12 successful frac stages. Can you walk through what happened from a -- not just the lateral length going from 7,000 to 4,000 feet, but with that lateral length coming down, did you get all stages off that you were able to get done? And how did you manage the proppant component of the completion and the benefits of starting through tubing immediately and how that can help from a production standpoint?

Robert C. Turnham

Sure. I mean, we -- yes, we were initially targeting a longer lateral. The rubble zone and the sloughing clearly caused us not to have to -- not to be able to get the full lateral length that we desired. Ultimately, when running production casing, we didn't get all the way down to what we had hoped to get to but felt comfortable with the 4,000-foot lateral and 12-stage frac, allowing us enough to get our target initial rates. And obviously, running tubing allows you to control the flowback, perhaps adjust chokes quicker and flatten decline curves, which we've said before is a goal of this well in our operation. So we feel like we -- obviously, the sloughing caused us to keep from getting the full length, but we certainly feel like we have an adequate lateral length. What we think is, you can hit your initial rates. And, for example, that -- the Pearsall well we talked about was 3,000- to 3,500-foot-long laterals, yet they achieved 1,400, 1,800 barrels a day. So you can flow the wells back at a higher rate. It's really more impactful on the EURs, in our opinion. So, the longer the lateral, the more feed in you get from more rock, the higher the EURs. But in this case, we feel like we can achieve our targeted initial rates.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay, great. And lastly on the TMS, the production impact that you mentioned versus the exit rate. It sounds like what the last contribution is, is just the timing of both the Crosby and the first Ash well. And it sounds like both of those are more likely, those combined with the second Ash well, are more likely to be January-type completion, so impact in the first quarter. Am I reading that right or was there something else beyond just the South Henderson sale and the timing of the TMS?

Robert C. Turnham

That's exactly it. It's -- you always circle dates on a calendar that are expected -- you're expected to commence frac-ing operations on and whether our service provider is a bit late getting there due to a previous well. That's always somewhat of a risk. But we would say the material difference is, as you stated, at South Henderson and then the 2 TMS wells are really -- had we not had those delays and not sold the property, we would have been in excess of 5,000-barrel-a-day exit rate. So still pleased with kind of where we are, but those were the primary reasons for the reduction in exit rate.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And Jan, on the tax rate, still have a 0% rate despite that gain. Any way to guess as to -- or what that did to your -- on the tax side in terms of when you may end up having to report taxes and LOE. Any color in terms of what you think the fourth quarter will look like?

Jan L. Schott

I'd say as far as LOE goes, we may see it move up a little bit, with the increased oil production, but we have been pleased by keeping that rate pretty low at least when we back out the workover costs on the LOE rate. So we like what we see there. As far as the tax rate, I'd say, for the time being, until we give additional guidance, I think 0% is probably safe to stay with. We have several NOLs that we really can work through when we do get into a position where we would be paying tax. So I think it's safe to say, at least for this year and even moving into 2013, a 0% tax rate is probably fair.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you maybe just talk about the -- of the total well at TMS, how much -- what percent is completion versus drilling or of the first well you drilled or what you have seen with EnCana?

Robert C. Turnham

Yes, we're typically seeing kind of 40% drilling, 60% completion. It does depend on lateral length, and that's how you derive the frac cost, obviously, with a number of stages. But I think that would be a reasonable level to consider. If you look at spread rate, which is rig rate plus all the other goods and services charged on a daily basis, we typically run $90,000 to as much as $100,000 if you're -- depending on the equipment you're running in the well. So every day, you shave off of that, you could see as much as $100,000 of cost savings. And frankly, that's what we did in the Haynesville. We went from 40 to 30 days. Just the more we drilled, the easier it is to develop optimum drilling practices. We expect that to happen here again. So I think I would use that as a rule of thumb if we can take it from 42, 43 days to 32 days, we'll save about $1 million off of the expected well costs. And then, as I said earlier, just once you prove up a play, just like we saw on the Eagle Ford, you're going to see increased competition with all service providers, and that will continue to drive down costs.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And can you maybe talk about, even if it's a non-op well, what not going in that rubble zone or that, I guess, that difficult 10 feet, what that could save in a drilling day's time?

Robert C. Turnham

Clearly, I think we talked about how much time we spent on the Denkmann, just dealing with washing and reaming due to sloughing. And no question, you're looking at 10 to 15 days. Just depends on how far out you are in the lateral and how many times you have to replace either drill bits or bottomhole assemblies or mud motors. Every time we came up while in the lateral and went back down, we couldn't necessarily start making new hole. We had to clean and wash to get back to where we were. And that's the real drag time. The Ash well just didn't have the same experiences. And the concept was landing above that 1 zone. Obviously, it's better rock and we just didn't see the same type of sloughing.

Brian M. Corales - Howard Weil Incorporated, Research Division

And if I could just ask one more on the Eagle Ford. You talked about 11 days. Was that an average that you're drilling these wells now? And if so, I mean, can 1 rig drill almost 30 wells a year? Is that -- in the Eagle Ford?

Robert C. Turnham

That's a factor in mobilization time, obviously. And if you're drilling one-off wells, you're looking at kind of 5 days mode, de-mode before you can start on a new well. But yes, 11 days was the average for an average 6,400-foot lateral, something in that range, which is tremendous progress based on where we had been, of 18 to 20 days typical drill times. That's it. Brian, one last thing is we could certainly grow volumes a lot faster if you just want to spend more money, but we feel it prudent to remain in the somewhat more defensive mode, keep our CapEx budget where we established it, show the financial discipline. And we feel like that's the right thing to do in this market, in which there are a lot of uncertainties, especially in light of the fact that we're seeing an improving gas market hold back some of the drive pattern and then be able to aggressively develop at the right time, in the right market, at the right mining price cycle.

Operator

Your next question comes from the line of William Butler of Stephens.

William B. D. Butler - Stephens Inc., Research Division

Talk a little bit more about gas, the improving gas price environment in the wells that you guys are going to complete as a non-op. What do you all think? There's been some other Haynesville operators that have been really working to get well costs down and are claiming that they can get them down. There's $8.8 million and they can go to $8.5 million or possibly $8 million, sort of on that Louisiana side. You guys, I think, have typically talked about $9 million as your midpoint. What do you think could happen next year in terms of without -- just with relative service capacity, et cetera, in this sort of $4 -- let's call it a $4 gas price environment. Could you guys achieve $8 million well cost there versus $9 million?

Walter G. Goodrich

Yes, William, this is Gil. First, let me make it very, very clear. We are not drilling any new and don't have any plans to drill any new Haynesville shale gas wells either in the remainder of this year or in 2013, unless and until the gas market improves appreciably above where it is today. So what we have talked about is the 6 net wells that were drilled, most of which were drilled in late 2011 and have been sitting cased but uncompleted here for the balance of this year. And in conjunction with our joint venture partner in the TMS, who operates the vast majority of those wells, they believe that it's prudent to move forward now with a completion to go ahead and complete those wells and bring those wells into production. So that's really all we're talking about for Goodrich in terms of gas. As to your more general question about the drilling costs, we obviously keep a very close eye on Haynesville-related drilling costs. We would concur with your comments that costs have likely come down from the $9 million to $9.5 million range to probably the low $8 million range. We have drilled wells back a couple of years ago as low as just under $7 million. So under the right circumstances, we certainly see that is being achievable. I would say that, again, however, even with those kind of numbers for Goodrich, given the ongoing delineation of the TMS, the ongoing pad drilling strategy and oil-volume growth strategy in the Eagle Ford, it's unlikely you'll see us start moving rigs to gas-directed drilling unless natural gas prices make an appreciable move up from where they are.

William B. D. Butler - Stephens Inc., Research Division

Got you. Certainly. And you all mentioned the Buda in your initial comments, but it doesn't sound like there are any plans to drill additional Buda wells. How should we think about Buda activity fourth quarter in 2013?

Walter G. Goodrich

Yes, I don't -- I think we're pretty happy with what we're doing on the pad drilling for the Eagle Ford. And as both Rob and I mentioned, we are in the preliminary phase of planning for a Pearsall Shale well. We're very encouraged about what we're seeing by a couple of offset operators who have made wells that are at least initially in the 1,400- to 1,800-barrel-a-day equivalent range, with about 75% of that being liquids and half of that being black crude oil. So if those wells hold up and continue to perform over the next few months, we would certainly be encouraged to initiate a Pearsall development program, but I don't see any Buda wells planned for the next 6 months or so.

William B. D. Butler - Stephens Inc., Research Division

I mean, does that make the Buda sort of an asset that you all could monetize in, if it's not a near-term priority or just...

Walter G. Goodrich

Potentially, William, but I think the bigger place for us would be in the Pearsall, more impactful, as well, of course, doing something, as we've talked all along, at the right time in the TMS.

William B. D. Butler - Stephens Inc., Research Division

Okay. One last question. I believe you all had your NGLs from the South Henderson field in your gas stream. And so, what kind of impact pro forma of that sale should we expect on differentials in terms of your gas realizations? And then -- that will be my last.

Robert C. Turnham

Yes, we really -- the liquids yield over there at South Henderson was probably 80 -- what would you say? That's the latest reading was on our liquids yield there, 85?

Walter G. Goodrich

Total liquids condensate...

Robert C. Turnham

No, no. Just the NGL portion. Yes. 85 barrels per million. We had about, call it, $9.5 million to $10 million a day of production during the quarter. So we're going to lose -- I think we had -- I think, Jan, you had...

Jan L. Schott

200 barrels of oil and 600 barrels of liquid.

Robert C. Turnham

Yes, 600. So 400 barrels of NGLs will come out of that, William, of the number that we gave you, which I believe it was -- so we had 4,600 barrels of total liquids. So we had 1,400 barrels a day of NGLs. So you're going to drop down to 1,000 barrels a day. We got about $33.50 a barrel in realized price for the total NGL stream. It's 50% ethane. So yes, you're going to have to drop that to 1,000 barrels a day of NGLs prior to declines. Our Beckville/Minden field and our Eagle Ford is really where we see the NGL volumes. Beckville/Minden is about 25% liquids, and about 75% of that is NGLs. And I would say we're doing about $15 million a day, if you want to do the math, as to what would be left in East Texas. And then in the Eagle Ford, we have NGL volumes comprising about 7.5% of our production stream down there, with, obviously, 85% black oil and 7.5% residue gas.

Operator

Your next question comes from the line of Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess quickly on my end, just curious on maybe a little additional color on the decision to move the rig back to the Eagle Ford from what was allocated in the TMS. Is that earlier than you'd previously kind of thought? It was a bit earlier than I was thinking. And as you talked about, you can build up a decent amount of inventory, I would think, in terms of wells drilled in the Eagle Ford. Do you have -- particularly now 2 rigs, do you have the frac contracts in place to take that inventory? Or just any additional color on those decisions.

Walter G. Goodrich

Yes, Michael, this is Gil. First, yes, you characterized it slightly wrong. We never moved it out. The anticipation was that we would move it out of the Eagle Ford and over to the TMS during the fourth quarter. And instead, it's just going to stay there. So it wasn't as if it left and it's coming back. It's just going to stay there. And we had contemplated all along that even if we did that temporarily by moving out of TMS, we would have another rig moving back into the Eagle Ford in early 2013, with the contemplation of running 2 rigs down there. So it's only a very short-term kind of change. And as Rob mentioned, because of delays that we saw in the Denkmann, which pushed the Crosby back, which pushed the Huff well back, then it made sense for us to continue on with a little bit more prudent approach to the TMS, keep the CapEx down there and leave the rig in South Texas, with the idea that we'll move on down the road here a few more months and then consider bringing potentially another rig over into TMS as results gel a little bit more.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And in terms of having frac contracts in place for '13, where do you stand on that in the Eagle Ford?

Walter G. Goodrich

Yes. So in terms of our capacity and ability to frac wells, we certainly have that today. We're still operating under our 2012 contract, which will expire at the end of the year. We're in the process now of going through our redetermination, so we'll be going out from bids here in the next week or so and generally, we would expect having some new in place in terms of the contract for 2013 sometime during December.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And what has that Eagle Ford kind of full well cost been looking like at this point?

Robert C. Turnham

Yes, this is Rob. I would say we've been averaging $8 million to $8.5 million for the year on average, kind of gross drilling. So call it 6,500- to 7,000-foot laterals is what we've been targeting. We have not recalculated what these last several wells that have come in, in an average 11 days, but I'll tell you, the drilling cost down there, it's a little more kind of like 1/3 drilling, 2/3 completion in Eagle Ford. And instead of a $2.2 million drilling AFE at, call it, 20 days, now we've shaved probably $500,000, $600,000 off of some wells. We can drill them in 11 days. So clearly, we're seeing great benefit to that. And obviously, churning out and cycling in more wells, yet our frac schedule has been set for a while. So we'll have a big backlog as we enter into 2013 that we can kind of kickstart our 2013 volumes from those fracs.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

So the $8 million in 2013 sounds like a fair way to think about it?

Robert C. Turnham

I think at most, yes. And perhaps, we can do a little bit better than that, but that's reasonable, assuming we continue to drill 7,000-foot laterals.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Got it. It's helpful. And then I guess just quickly jumping over to TMS. As it relates to landing the lateral above the slough zone, is there any -- are there any potential implications on the frac in terms of landing above that zone? I mean, is there -- I guess I'm just trying to think through like what are the potential risks around doing that. And like you said, you're evaluating a couple of other approaches to dealing with the slough zone. Just trying to think about the completion side of it as opposed to just the drilling side. Anything we got to keep in mind in that regard?

Walter G. Goodrich

Sure, Michael. This is Gil. So our original landing target was approximately 15 to 20 feet off the bottom of the TMS. The fractured zone or rubblized zone is approximately 40 feet off the top of the TMS, and I say it's approximately 10 feet thick. So we are moving up to where now our target zone is roughly 50 to slightly above 50 feet off the top -- excuse me, off the bottom. Now in a 100- to 150-foot interval, as you know, we are moving up a little bit. So there is at least some fairly modest concern about full stimulation. However, we think if the lateral is roughly 50 feet off the bottom, we don't see any reason that the entire TMS should not be effectively stimulated. But we'll certainly want to watch the Ash, in particular, and watch that well's performance. And all things being equal, we'd rather be down in the bottom 20 feet. So that's why the Crosby approach of getting through it and getting it behind pipe is also a very viable option. I'd say that if we have no ongoing issues or concerns relative to frac stimulation, effective frac performance, et cetera, then landing above it would be the ideal remedy.

Operator

Your next question comes from the line of Leo Mariani of RBC Capital Markets.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just trying to get some color on when you think this Denkmann well is going to be repaired and when that can go on in production.

Robert C. Turnham

Yes, I think -- Leo, this is Rob. I think in my remarks, I said 3 weeks. We'll set a CapEx budget early December with Board approval, and hopefully, we'll be in a position to discuss the Denkmann. It's just a matter of how long the patch takes, then drill out the plugs, then run tubing. And we typically see peak rate after about a week of flowback. So it's just dependent on that. But we've said just a matter of a few weeks is what we would expect to have peak rate established.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess any color on how that Joe Jackson well is looking thus far?

Robert C. Turnham

No. That's EnCana's operated well. They have the right to announce that and discuss that. And frankly, it's just started. So I don't even think -- even if they wanted to announce it, we're just not there yet. So hopefully, we'll be able to give an update on that as well when we have the Denkmann well.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And in terms of the decision to do a JV either out of the Pearsall, the TMS, and you also mentioned additional asset sales, is it safe to assume that if you were to do a significant JV out of the Pearsall or TMS, that maybe that would take asset sales off the table. Is that going to be kind of an either/or type situation there?

Robert C. Turnham

We'd like to see them get some capital of $100 million coming in the door, if possible. We'll just have to see what the optimum divestiture or JV might be. We can always sell the Pearsall if we have the right valuation also. But we're intrigued by the early well results and obviously, that would give us another leg to the stool on development, which is why we're playing that. But I think Beckville/Minden is the obvious noncore asset sale, if you wanted to target that, doing about $15 million today. So that's probably in the range of $100 million if you wanted to sell that. But it all depends on commodity prices. That field is worth a lot more as gas prices improve, and that's why we'd like to get into early 2013 before we decide what we want to do on that.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. You talked about quite a while back about doing a JV in Angelina River when gas prices, I guess, were on the way down as opposed to the way up. Is it ever possible that might get revived in a higher-gas-price environment?

Robert C. Turnham

Yes, absolutely. We're very excited by the well results we've seen even of recent times. EOG drilled a well that looks incredibly good to us, made over 2.5 Bcf in 5 months. So at 30,000 net acres there, if we have the Haynesville perspective and the Bossier Shale, the well cost, call it, $12 million for 10 to 12 Bcf-type wells, looks awfully good and it's going to be worth a lot once gas prices improve. So that clearly could be back on the table if we see better gas prices and better valuation metrics. So that's an obvious solution also just to help us jump start the development there by bringing in fresh capital.

Operator

Your next question comes from the line of Mike Scialla of Stifel, Nicolaus.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Gil, you said you're not ready really to project any EURs for the TMS yet. But I think you guys have said in the past that if you could get the well costs in that $12 million to $13 million range, you kind of need a minimum of 350,000 boe to reach a hurdle rate. And I know you've seen some pretty steep initial declines here. But, Rob, you mentioned some of the longer-term rates you're seeing out of Anderson and some of the other wells. I'm just wondering, have you seen enough yet to feel like you can get above that minimum threshold? Or is it still too early to say?

Walter G. Goodrich

Yes, Mike, this is Gil. I think you're right on point. I think we would agree that's kind of the minimum number, somewhere in the 300,000- and 350,000-barrel range. And we've said many times now that we're very, very encouraged, and even the first grassroots well was only a 15-stage frac. We think it's still early. 11 months doesn't completely make a tight curve, but we certainly feel like that well is going to land above that minimum threshold. And certainly, the 2 longer laterals are going to be significantly above that based on early-time performance.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then what's the next well in the TMS after the Crosby? What's the timing on that? And have you decided yet how you'll -- you said you're trying these different alternatives. Have you decided yet how to drill that one? Or do you want to wait and see how the Ash well performs before you make a decision there?

Walter G. Goodrich

Yes, that's a great question, Mike. I think ideally, we'd like to see how the Ash well performs. We're going to continue our dialogue with our partner EnCana out there between now and the time that, that well is spud. I think in terms of getting through it and casing it off, all we're really talking about is moving the base of the intermediate casing stream from the very top of the TMS, which we have to set it at that point anyway, down about 50 to 100 feet. So we're really not talking about any incremental cost. So I think we view that as a pretty good insurance policy, and we have made a final determination internally. But I would say, given that the Crosby goes as we expected it will, that would probably be the way we'd lean right now until we can see a little bit lengthier production performance from the Ash well.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So in terms of drilling that next one after the Crosby, you may not need to wait until you see results out of the Ash. Is that fair?

Walter G. Goodrich

Yes, I think that's fair.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then anything that you saw on the core of the Crosby that would lead you to believe the western side of your acreage is any different than what you've seen over the east?

Walter G. Goodrich

No. We always see nuances of geologic differences from one place to the next. But we pretty much saw on quick digital inspection, this is just last week, exactly what we were expecting to see. We were able to see very, very clearly and identify this 10-foot, very highly naturally fractured interval, which is clearly the culprit in the well bore stability issues in our minds. And we feel pretty good about it. So we'll see. We'll get the well down. Obviously we're moving towards getting the lateral drilled, and we'll be moving towards completion soon thereafter.

Operator

Your next question comes from the line of Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

On the TMS, can you review the royalty burden and the severance tax regime?

Robert C. Turnham

Yes, Dan. 20% average royalty burden across our acreage. It does vary unit to unit, but that's a good blend to use. We're looking at really no severance tax in the State of Louisiana. They've had the horizontal severance tax abatement for a couple of years. So obviously, a big benefit there in Louisiana. And then Mississippi, very similar to the Eagle Ford. I believe it's a little over 6% severance tax on oil. So certainly, the TMS has 20% to 25% advantage right now, and the fact of LLS pricing being the breadth of TI spread is obviously very large, $20 or so, and then about 5% less royalty burden. So we're playing with the ability to be able to spend a little bit more money as long as we see a similar decline curve to the Eagle Ford wells, and certainly feel encouraged early on that we have at least that on the decline curves.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And then at the top of the call, you spoke about the Anderson 17H well, where you have a 7% working interest, I believe. And you gave a rate in over a period of time. Can you say that again? I missed it.

Walter G. Goodrich

Yes, this is Gil. What I gave, Dan, was just a snapshot. I think we'll let EnCana disclose in terms of overall performance. But the well has been on a little over 5 months, and it's producing a little over 300 barrels a day.

Dan McSpirit - BMO Capital Markets U.S.

300 barrels a day, okay.

Walter G. Goodrich

Of oil.

Dan McSpirit - BMO Capital Markets U.S.

Right. Got it. Got it. And let's see here. On the $12 million to $13 million drilling complete cost, does that assume a 4,000-foot lateral length? And is a longer lateral length possible considering the depth and pressure involved?

Walter G. Goodrich

Yes, our $12 million to $13 million assumes about a 7,500-foot lateral linear in approximately 25 stages.

Dan McSpirit - BMO Capital Markets U.S.

Okay. Great. And then turning to South Texas. On your northernmost leasehold in South Texas in the area, the Pearsall perspective leasehold, how do the Eagle Ford shale recoveries and costs change from wells completed more in the core area of your leasehold further south? Just trying to get a range on EURs and drilling complete costs across the 2 areas.

Robert C. Turnham

Yes, we've always talked about as you head north and west in particular, you get more shallow. So we're looking at about 2,000 feet difference from the top to the bottom of our acreage block. And on the drill side, it's not, believe it or not, it doesn't take a whole lot longer, call it a couple of days, to drill the added depth in the lower portion of the acreage. So not seeing a huge amount of cost savings difference. And frankly, we haven't drilled an Eagle Ford well in that area, certainly for over a year now. So lower IP rates, a little bit flatter curves, but obviously lower EURs. And so we're just pounding away in the southern 60%, where we're seeing better results. The Pearsall sits about 2,500 feet below the Eagle Ford, maybe 3,000 at its peak. So we expect a similar drill cost, call it $1 million to $1.5 million additionally, to drill a Pearsall well no matter where we drill it, whether it's on the north side or the southern side.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And then the PUDs that you booked for the Eagle Ford last year, what were those booked at? What were the recoveries on your PUDs?

Robert C. Turnham

Yes, Dan, if you'll hold that question, we're about to post a new investor presentation next week that will give you what the well performance has been across the entire block. And it's a little bit less than our mid-case curve but not a lot, and we're going to be able to show you that. So we typically see a little bit of discounting on PUDs. That's just how [indiscernible] does it off of the proved producing. But I think you'll -- I think you'd be happy. It's a good slide we did. We've been doing it in the Haynesville and decided to go ahead and release an Eagle Ford curve like that also. We'll be in a conference next week and as a part of that, we're going to have this updated type curve and actual well results.

Operator

Your next question comes from the line of Richard Tullis of Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Just a couple of things I don't think have been touched on yet. Gil, what's the estimated rate of return on those Haynesville wells down in Angelina that you'll complete next year? Just using the $22 million cost to complete them in, say, a $4 gas environment?

Robert C. Turnham

Yes, Richard, I'll take a stab at that. This is Rob. Really, it's tremendous when all you're doing is amortizing the completion cost. Obviously, we've actually 2 of the gross -- we have 13 gross wells; 2 of those have actually already been frac-ed. So we've incurred full well cost on those 2 gross wells. And then the remainder, which would be 11 gross, call it, 5 net wells are only going to cost us $22 million. So a little over $4 million completed well cost or completion costs associated with the wells that have already been drilled. And as Gil stated in his remarks, the revenue associated with that net to us is about the same as the CapEx. So $22 million of gross revenue associated with those wells. So real quick payout based on your completion dollars. Don't have the rate of return on that. But, obviously, that's about half of the completed well cost if you were to drill it at $8 million a well. So the IRR on that is going to be really, really high. At $4 gas, if you just take kind of average well cost that we've had in North Louisiana, you're looking really at probably, call it, a 20% or maybe 17% IRR. So if you want to kind of double that, that's probably a reasonable basis. But that's -- it's not something that we're choosing to do. We just know that that's in the plans. And I believe our partner's looking at it exactly that way, is we're down to completion dollars now, what kind of rates of return and cash flow can be generated from that, hence completion dollars.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Remind us again what's the typical IP rate for those wells?

Robert C. Turnham

Yes, we've been under restricted shale programs in that area for quite some time and kind of $10 million to $12 million a day of initial rate and a much flatter decline than what the original year 1 decline had been forecasted, which was 80% -- 80% to 85%. So I kind of ballpark, take $10 million a day and decline it at 60% or thereabouts wouldn't be a bad modeling methodology.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And then given that production online next year, what do you think your oil liquids component of total production will be for 2013?

Robert C. Turnham

All depends on CapEx allocation. And we'd really not done that yet, but we're going to exit this year at 30% of production and, call it, 75% to 80% of revenue coming from oil. So if we're spending $22 million in gas and then we wind up spending something similar to our budget in 2013 than we have this year, no question of liquids ought to -- or oil ought to comprise 40%, 45%, you would assume, of total volumes. The 10% growth in gas next year is really -- if you take fourth quarter of '12 to fourth quarter of '13, and you'd complete those wells in the first half of the year, with more skewed first quarter than second quarter, then you can basically get to that 10% growth.

Operator

Your next question comes from the line of Steven Karpel of Crédit Suisse.

Steven Karpel - Crédit Suisse AG, Research Division

Maybe going back somewhat to try to understand the liquidity picture. If, I guess, maybe the first part to ask is, with the asset sale, should I think of it directly that the $55 million borrowing base is directly connected to the $95 million? Or was there any other impact that you see? I know it's a bit of a black box but...

Robert C. Turnham

Yes, no. That was a part of it, no question about that. But their price deck looks certainly less and our hedges -- what they do is they roll forward about 6 months before taking into effect the reserves at their price deck. And in that, we are -- we lose our gas hedges in 2013. We certainly expect to add gas hedges as prices improve. But as we sit here right now, you lose the benefit of your hedges on gas for the second half of 2012. That, along with the kind of a $3 price deck and $75 price deck on oil, less any hedge value, you certainly get an impact from just lower price deck.

Steven Karpel - Crédit Suisse AG, Research Division

Were you able to show the banks any new reserves that they gave you credit for? Or did they give you the old reserve report?

Robert C. Turnham

No. We updated the reserve report with new wells drilled in the first half of the year. Again, obviously, they're coming in at -- for 2013 at their price deck at $75. But it's the 6-month roll forward and really, the loss of the gas hedge along with just reduced price deck, obviously, is what affected it. And then South Henderson was probably a little more than half of the value that we lost.

Steven Karpel - Crédit Suisse AG, Research Division

So if you look at on a total liquidity basis, what do you -- how do you think about what you need? And obviously, the South Henderson sale, just to take your comments at the beginning of the call, fills the 2012 gap. What do you need to do to fill 2013 and -- or maybe just fill 2013 by cutting back CapEx? And how much can you cut back?

Robert C. Turnham

Well, we can cut back quite a bit. We stagger our rig contracts so that we can release them if needed. One of the 2 Eagle Ford rigs right now is on a short-term basis. That would be easy to release. The TMS rig is just basically kind of well-to-well with 30-day notice. So we're in good shape there as well. So you're actually right. The true defensive stance would be let's just cut CapEx. We have plenty of time in the Eagle Ford. We hold all that acreage. We're still within primary term on a good bit of that. And then the TMS, we have anywhere from 18 months to 5 years of term on those leases. And then after that, we have continuous drilling provisions still come with the leases. So plenty of flexibility on cutting CapEx. I think that the reality is, as we've stated, by the end of the first quarter, we and the rest of the industry will have 20, 25 wells drilled in the TMS. If you look back at the Haynesville, the Bakken, the Eagle Ford, the Utica as the great, recent example, it takes about that many wells to not only prove up what the production and EUR estimates look like, but to get your well cost down. And at that point, we think we'll have the economics proven. And that gives us a better opportunity to bring in a partner at a better valuation if we choose to go that route. And there's quite a bit of interest already in that process. We just -- or in that possibility. We just haven't started the process to bring in a partner yet. We do expect to bring in fresh capital. It's not going to be stock -- selling stock at anything close to this, and it's likely not going to be that at any price. It's likely going to be either the JV or selling of a noncore property.

Steven Karpel - Crédit Suisse AG, Research Division

And maybe you mentioned equity capital, how about debt capital? And is it...

Robert C. Turnham

That's always a possibility. You could do a tack-on to your high-yield or even a new issuance. But we really view 2013 as a time to perhaps improve the balance sheet by doing one of these other transactions. And that's going to be -- rise to the top of the priority list versus layering on additional debt. But the high-yield market obviously is still in play. We just feel like it's time to bring in a partner and help us develop some of these plays. And as Leo mentioned earlier, with a better gas environment, we're already seeing quite a bit of interest in the Angelina River Trend if we want to go that route, and that could make some sense also depending on valuation.

Steven Karpel - Crédit Suisse AG, Research Division

And then just last one in -- just curious on any of the gas wells? A lot of these are non-opt. Have you opted out of any? And if so, why not?

Robert C. Turnham

We've already drilled those wells. We did opt out of a couple of wells that were proposed a year or so ago, just didn't feel like it was the right thing to do. But all of these wells have either been drilled, waiting on completion or a couple of them have actually been frac-ed and have been shut in. So in this case, as you can see, to get -- to spend $22 million on 6 net wells, that's quite a little investment to achieve a $22 million of revenue in a year's time. So we feel like that's an easy decision to make. You do have the flexibility to opt out of future wells if those were proposed. We don't feel like that's going to be the case after a discussion with our partner up in North Louisiana. But that option is available. And you'd basically be out of that well versus out of any acreage.

Operator

Your next question comes from the line of Pearce Hammond of Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

A question on the Haynesville. Do you know how many wells might be similar to these 5 wells that need to be completed, the ones that are essentially cased but waiting on completion? Are there a bunch of them out there? And could it impact the gas supply/demand outlook for next year?

Robert C. Turnham

Pearce, this is Rob again. I've read sell-side firms that try to track that, and last estimates I saw were 100 to 150 potential wells, although that inventory has been dwindling as companies have completed those wells. So I'm not sure. We've not totally tracked that. I think it's certainly going to bring back some supply in North Louisiana. However, the rig count continues to plunge so dramatically there, and we're a great example of if you don't spend any money drilling or completing gas wells, your gas production falls. 60% -- oh, probably 60% of our production has been coming from the Haynesville, and our volumes are falling. So we feel like even if there are wells waiting on completion, it's just not going to be enough to curtail the declines that are coming from wells that -- fewer and fewer wells that have been drilled and completed. So don't have a definite answer for you there. But it's just not -- it's not what it once was when you had 400 wells shut in, waiting for completion. I think the bigger question is just in the Marcellus, how many wells are there? What's the increased capacity -- takeaway capacity in November? How is that going to alleviate some of that? We think the Haynesville is going to -- is already falling and will continue to fall regardless of completing some of these back-loaded wells.

Pearce W. Hammond - Simmons & Company International, Research Division

Great color. And then switching to the TMS, what are your thoughts on quality and availability of services in the play right now?

Robert C. Turnham

Well, we use Halliburton to frac our wells over there as we do in the Eagle Ford; obviously, they do a great job. We've used other operators in the past frac-ing our wells who have done an equally good job or certainly, very good jobs as well. So we feel like we have enough capacity on the pressure pumping side that's in close proximity to get reasonable frac cost. And in fact, we've already seen a reduction from the first wells frac-ed in the area to our current frac cost per stage. Feel like that's in good shape. The rig market is fine. In fact, our rig costs of late have been down probably 20% from where they were at one point. So that part has been good. It's all the other goods and services that are having to drive in from other areas, in particular North Louisiana, for example, that are still having to cover for their cost to move in and move out. I think once you prove the play up, that's where you start to see vast improvement in all the other goods and services. And we're pretty comfortable or certainly confident that over time, as Gil stated, we'll get these well costs to $10 million. And when you combine that with a decline curve and the economics associated with those wells that are, we think, that certainly the decline curve's as good as what we've seen in the Eagle Ford, along with the added benefits of better pricing from LLS and better royalty burdens, we think the economics are going to prove out. We're just early in the game. We just need to get a little bit further down the road before we put that stamp on it.

Operator

Ladies and gentlemen, I would like to return the call back over to Mr. Robert Turnham, President and COO, for closing remarks.

Robert C. Turnham

Thank you very much. We appreciate your interest in this quarter's earnings call and look forward to reporting year-end '12 results early next year. Thank you very much. Bye.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great week.

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Source: Goodrich Petroleum Management Discusses Q3 2012 Results - Earnings Call Transcript

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