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Goodrich Petroleum (NYSE:GDP)

Q3 2013 Earnings Call

November 05, 2013 11:00 am ET

Executives

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

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

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

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

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

John Freeman - Raymond James & Associates, Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

Stephen F. Berman - Canaccord Genuity, Research Division

Chad L. Mabry - MLV & Co LLC, Research Division

Phillips Johnston - Capital One Securities, Inc., Research Division

David Snow

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2013 Goodrich Petroleum Earnings Conference Call. My name is Philip, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed, sir.

Walter G. Goodrich

Thank you, Philip. Good morning, everyone. Welcome to our third quarter 2013 earnings call. With me on the call this morning is Pat Malloy, the company's Chairman of the Board; Robert Turnham, President and Chief Operating Officer; Mark Ferchau, Executive Vice President, Engineering and Operations; Jan Schott, Senior Vice President and Chief Financial Officer. And I'd also like to welcome back Daniel Dickins, who's our Director of Corporate Planning and Investor Relations, who recently rejoined us after a brief stint away.

As is our practice, we'd like to remind everyone that answers to questions that we may give and comments we may make during this conference call are considered forward-looking statements, which involve risks and uncertainties, and we have detailed those for you in our SEC filings.

In the third quarter, total production increased 16% on an Mcfe basis versus the second quarter of this year to approximately 83.7 million cubic feet of gas equivalent per day. Total production was led by crude oil, which increased to approximately 4,100 barrels of oil per day, which is a 28% increase over the second quarter.

Natural gas production also increased sequentially by 11% to 59.3 million cubic feet a day in the third quarter. Our realized natural gas prices came in below estimates for the second quarter at $3.15 per Mcf, crude oil prices remain very robust and improved during the quarter to an average of $106 per barrel.

While we remain completely unhedged on natural gas during the third quarter, beginning in October, we have 10 million cubic feet per day hedged through the end of this year at $4.18 per MMBtu.

For calendar year 2014, we have 30 million a day, or approximately 50% of the average third quarter natural gas volumes hedged at a blended price of $4.76 per MMBtu.

In addition, during the third quarter, we added crude oil hedges covering the period from November of this year through December of 2014, which increases our crude oil swap hedged position for next year to 2,500 barrels per day at a blended average price of $93.18 per barrel.

Improving production volumes and strong realized crude oil pricing led to improved cash flow, with adjusted EBITDAX growing to approximately $35 million or a 10% sequential increase over the second quarter.

While our pad drilling wells in the Eagle Ford have impacted crude oil productions over the past few quarters, it has led to excellent cost reductions on the average Eagle Ford pad-drilled well.

In the third quarter, we reported a 16.5% reduction in per unit DD&A on a company-wide basis, which was the result of both improved EURs and lower average well costs in the Eagle Ford shale.

Turning to the balance sheet. Thus far, in 2013, we have significantly enhanced our balance sheet and liquidity and made tremendous progress in eliminating any near-term maturities.

Through a series of transactions, we have now escrowed funds sufficient to redeem all remaining convertible notes, which have an initial put call date in October of next year.

In addition, we have extended the maturity on all of the remaining 5% outstanding notes to October of 2017.

The increased crude oil reserves and lower Eagle Ford well costs also led to an increase in our borrowing base at midyear under our senior credit facility, an increase to $270 million.

In addition, our recent equity offering has us extremely well-positioned to accelerate our pace of development in the Tuscaloosa Marine Shale play. The equity offering incorporated on a pro forma basis as of the end of the third quarter provided us with no net debt or borrowings under our senior credit facility and approximately $134 million of cash, including approximately $52 million of restricted cash in escrow.

If we add the revised and expanded borrowing base of $270 million and no net of borrowings to our total cash position, including escrow cash, total pro forma liquidity at the end of the third quarter would have been just over $400 million.

The significantly enhanced balance sheet will allow us to execute an increased capital budget and acceleration of the TMS in 2014.

As we recently announced, we have added a second rig to the TMS, which is drilling our initial joint well with Sinopec on the acreage we acquired this past summer.

As we move into 2014, we currently plan to add a third rig early next year and add incremental rigs such that we exit next year with 5 rigs back into the play.

To accommodate the increased activity, we recently announced a preliminary 2014 budget of approximately $375 million, which will allow us to take advantage of near-term delineation opportunities and move at a more rapid pace towards development drilling in the TMS.

With that, I'd like to turn over to Rob Turnham for an operational review.

Robert C. Turnham

Thanks, Gil. As Gil stated, we currently have 2 rigs running in the TMS, going to 3 rigs in the first quarter of 2014, and 5 rigs by the end of the year with continued success.

We've established a preliminary capital expenditure budget for 2014 at $375 million, with $300 million allocated to acceleration of development of the TMS, where we estimate that we will drill or participate in as many as 31 gross, 24 net wells, which is a blend of 100% working interest wells and 67% working interest wells.

We are budgeting 45-day drill times, although we think we will do better, 60 days spud to spud, and 75 days spud to sales cycles times.

We continue to be optimistic with the resource potential of the play as our Crosby wells cumulative production has reached 138,000 barrels of oil equivalent per day or over 90% crude oil in 8.5 months, with a current rate of approximately 250 BOE per day on a very flat declining curve. This would compare to similar cumulative production from the Anderson 17 #1 well in 15.5 months, and 155,000 BOE for the Anderson 18 #1 in 16 months. When considering recent wells in which we've operated or participated as an non-operator, 5 of the last 6 wells are trending on or between our 600,000 BOE and 800,000 BOE curves, with the oldest of these wells now approximately 18 months old.

The Crosby well continues to perform in excess of our 800,000 BOE curve. We have been pleased with the performance of the Crosby well on jet top and continue to tweak artificial lift parameters to flatten curves and maximize production.

We have drilled our Huff well in Amite County, Mississippi, with 5400 feet of usable lateral. We drilled the curve and lateral in a record time of 12 days but have experienced completion delays due to temporarily sticking to drill pipe, which we have now resolved, and cleaning up the wellbore prior to running production casing.

We expect to be finished with our cleanout operations within the next few days. We'll then run production casing and frac the well.

The completion delay is frustrating, but the drill time for the curve and lateral of 12 days is very encouraging for the play. We believe our ability to knock at least 10 days off of our 45-day ASP of $13 million, which will save $1 million in drilling costs is very achievable, considering that we normally drill the vertical portion of the well and run intermediate casing in less than 25 days.

In addition, we are seeing more competitive service company bids and expects cost to improve further with continued success at higher activity levels in the play in 2014.

We also intend to drill a few pad-drilled wells in 2014, which will further drive well cost down to the rigs skids instead of moves, amortization of facility costs over multiple wells and simultaneous or zipper fracs, which allow for more efficient use of pressure pumping equipment.

As Gil stated, we spudded our Weyerhaeuser 51-1 well last week, which is the initial well on our newly acquired acreage with our partner, Sinopec, with plans to drill 3 wells back to back on the acreage.

After the Huff, that rig will move to the CMR 8-5 well in Amite County, Mississippi. The 3 wells drilled on Sinopec JV acreage will be spread out from the Weyerhaeuser in the middle to a well on the east and an additional well to the west.

We continue to see very consistent results across the CMS when similar frac recipes are pumped. The increased activity levels in 2014 from us, Encana, which today announced it will spend $200 million to $300 million in the TMS next year, and other companies we know are building positions, to allow for rapid delineation and progression to development mode for the company.

For the quarter, we spent $91.4 million in capital expenditures, of which $66.3 million was spent on drilling and completion costs, $22.7 million on the company's producing property and leasehold acquisition in the TMS and $2.4 million on other leasehold acquisitions and extensions, facilities and other expenditures.

We are on pace to hit our previously announced amended 2013 capital expenditure budget of $255 million.

Of the totals for the quarter, 32% of the capital went to the Eagle Ford, 57% to the TMS, which includes the property acquisition and lease extensions, and 11% towards completing some Haynesville wells that were drilled in late 2011, early 2012.

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 $57.2 million, an increase of $11.2 million or 24% over revenue for the comparable period last year, and an increase of $8.7 million or 18% over the second quarter of 2013, with oil representing about 70% of oil and gas revenues for the quarter.

Our third quarter average realized prices were $106.11 per barrel for oil, and $3.15 per Mcf for natural gas. Our average realized price was $7.38 per Mcfe for the quarter.

For the balance of 2013, we have 4,000 barrels of oil per day hedged at a blended price of $94.79, and 10,000 MMBtu per day of gas hedged at a blended price of $4.18.

As Gil covered earlier, this quarter, we added to our 2014 hedged position. Please see our website for more detail on our current derivative position.

Moving on to expenses. LOE this quarter was $7.1 million or $0.92 per Mcfe, up $0.9 million from prior year quarter and up $1.2 million from last quarter.

The third quarter includes about $1.6 million or $0.21 for workovers, primarily in the Eagle Ford Shale.

DD&A per Mcfe was $4.33 for the quarter compared to $5.18 last quarter and $4.80 for the prior year quarter.

As Gil stated earlier, improved EURs and lower average well cost in the Eagle Ford Shale play drove the rate improvement. We would expect rates to be similar in the fourth quarter of this year. We will adjust DD&A rates in the first quarter of 2014 upon receipt of our yearend reserve report.

Exploration costs for the quarter of $4.1 million or $0.53 per Mcfe includes $2.9 million for lease explorations and $0.5 million for amortization of leasehold or a total of $3.4 million in noncash expense.

At last quarter, the expiring acreage was mostly located in the Northern section of our Eagle Ford Shale position.

G&A costs came in at $8.3 million or $1.08 per Mcfe this quarter compared to $0.92 in the prior year quarter and $1.15 per Mcfe last quarter.

About $0.23 or 21% of the third quarter rate represents noncash stock-based compensation.

We recorded a $4.8 million loss on early extinguishment of debt. In August, we exchanged half or $109.25 million of our outstanding 5% convertible notes for new notes with an initial hold date of October 2016 and an initial put date of October 2017.

The loss mainly represents the unamortized debt issuance cost and debt discount associated with the original 5% notes.

After quarter end, we exchanged another $57.4 million of original 5% notes for $57 million in new notes.

We are projecting a 0 tax rate for the full year of 2013.

Continuing our efforts started earlier this year, we have continued to improve our liquidity position, shore up the balance sheet and position the company for a ramp-up in the TMS in 2014.

I would like to walk you through our current liquidity position based on the recent equity offering, 5% convertible note exchange and our recent borrowing base redetermination.

First, at the end of the current quarter, we had $1.9 million in cash and $143 million drawn on our senior credit facility, which had a $243 million borrowing base, for a total of $102 million of liquidity at September 30.

We ended the quarter with $109 million in restricted cash so that the maturity on our credit facility was extended to February 25, 2016 at quarter end.

On October 2, we closed on the exchange of $57.4 million of our 5% convertible notes for new notes and released $57.4 million from restricted cash. Our restricted cash to date stands at $51.8 million, which is the same amount as outstanding 5% convertible notes with a put date of October 1, 2014.

On October 21, we closed on an equity offering, which brought net proceeds to the company of $166 million. Our borrowing base was recently increased from $243 million to $270 million. We currently have 0 borrowings under our revolver.

The next redetermination of our borrowing base will occur in April 2014, based on our yearend reserve report.

As mentioned in the press release, our pro forma 9/30 liquidity is $352 million, with $51.8 million in restricted cash for a total of $404 million.

We have updated our cap table in our management presentation for 9/30 and pro forma to reflect each of these items and we'll post our updated management presentation later today on our website.

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 2013 10-Q with the SEC later today. Please see our 10-Q for a more detailed financial discussion.

And with that, I will now turn it back over to Gil for some closing comments.

Walter G. Goodrich

Thank you, Jan. While challenges remain, we continue to make progress in defining what we consider best practices in the TMS drilling and completion operations. The 2 rigs running into play, acceleration coming in 2014, and what we now believe will be an increased industry activity, we are excited about the development of the play and looking forward to reporting those results to you as they occur.

And with that, I'll turn it back over to Philip for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

For Gil or Rob, just wondering now, when you look at, obviously, the wells now that you completed and the ones that you currently have going, your thoughts about the type curve if you would look at, obviously, I think, you commented about how these wells are trending versus the type, as far as versus the type curve on a BOE expectation, but maybe if you could further comment on sort of costs, where they currently are, as well as sort of different IP rights and different things around the curve?

Walter G. Goodrich

Sure, Neal. This is Gil. So first on the cost piece. We continue to build AFEs right at about $13 million. Obviously, on the Huff, we're going to incur some incremental expense, don't know exactly the magnitude of the delays that Rob referred to in his commentary. But I think, if you take those delays out, which hopefully we'll get better at over time, clearly, that well would have been at or within the $13 million range. So continued longer term in a broader scale feeling very good about a range, and I know that Encana said this morning $12 million to $14 million, we certainly would concur with that, with an eye towards getting better as we get into some development drilling next year to bring those costs down. On the IPs, we certainly are pleased. As Rob said in his commentary, we've seen 5 of the last 6 wells have come on are tracking within the 600,000 to 800,000 BOE curve. I don't think we're ready to pound and save on any specific 1 curve, but certainly something in that range looks very economic to us. And we haven't seen anything that really concerns us about that at this point in time.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then, activity on besides the next couple of wells, and at Weyerhaeuser, you've kind of outlined those next 3 wells. Your thoughts on for with all -- if you do -- when you do go to the 5 rigs, well, most of that activity, I guess, is it going to be kind of spread out to delineate the acreage or you will be pad drilling, or can you kind of explain that?

Robert C. Turnham

Yes, Neal, this is Rob. Well, initially, we have a core right in the middle of our block that we feel like has already been de-risked, you can kind of put a circle around wells that are producing and make some adjustments for how they completed the wells, obviously. But we feel like we've got a nice core acreage position that's already de-risked. You will see us with a combination of stepping out away from the core in a gradual manner, and in particular, locating wells near Devon wells, in particular, on our acreage block, where we could put the proper or the more effective completion recipe on those wells. So the Weyerhaeuser 51 #1 is going to be a great example of that. We're in an area where both Devon and Encana had drilled wells on the Weyerhaeuser block. We'll then move to the east, over kind of near the Devon, Thomas and known vertical well called the Texas Pacific Glades well locations are, so that will give us a nice data point to the east. We'll then move to the west from Weyerhaeuser, kind of towards Richland Farms, Beech Grove and Murphy wells. If you look at our budget, and it's going to be fluid, it's going to move, but we've in essence basically modeled about 60% of our activity on the formerly Devon acreage, and 40% on our legacy acreage, that could change with results and goals. We do expect to start capturing acreage by drilling off of pads in 2014. It won't be theoretically drilling within the same units, but forming units side-by-side and capturing the acreage with 1 pad where you can amortize the facilities and reduce your well costs. So we're still very comfortable with our abilities to reduce well cost over time. And as you know, we've targeted current well costs of $13 million. And I think, over time, we can drive those costs down to $10 million, with a combination of knocking 10 days off the drill time, pad-drilled wells with zipper fracs and reduced service costs.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then, just 2 more if I could, really quickly. Just on the -- maybe a little more color, Rob, just on the Huff well. It sounds like there really wasn't a delay because of how long you've got -- took you on the lateral. Maybe if you could just give us an idea on the timing, how much longer, maybe any more color you could add on sort of the expectations to case that and then when you'll start frac-ing that?

Robert C. Turnham

Yes, kind of in my prepared remarks, the real positive was that we were able to build the curve and the lateral in 12 days. And if you look on a go forward basis, we typically can drill the vertical portion of the well and run intermediate casing in 25 days or less. So theoretically, that well could have been 37 days or less had we not had the issues. What we found was that while drilling the lateral, it went as smooth as any of the wells have gone with very good wellbore stability, we reached a point at the very end of the lateral where we torqued up, obviously had some type of effect, whether it was a highly fractured area. And as you know, we're in an over-pressured environment. We may have done that, we were making such progress that we attempted to kind of push forward and get through that highly fractured zone. We were able to do that, but when coming out of the hole, that's when we got stuck. We ran a 3.2 [indiscernible] which condenses at the -- we were just stuck near the bit, we were able to back off out of the well and pull out on the hole, and it's now gone back in and are gradually cleaning out the wellbore. And we're taking our time because what we want is our best chance that a clean wellbore that we can run casing to bottom. And we're just 2 or 3 days away from that being finished. But we're encouraged by that. We would expect to then run production casing immediately after that, get the rig off location and move the frac equipment in as soon as possible.

Operator

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

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

Just on the drilling plans as you kind of go forward, you outlined the second rig really staying on the Devon acreage and it sounds like more southern acreage and moving from east to west. Any incremental information in terms of as you have now had the course in hand, what you're seeing on the core data and comparability across your acreage and the Devon/Sinopec acreage in terms of increased comfort of the similar rock qualities?

Walter G. Goodrich

Yes, Ron. This is Gil. We included a slide or 2 in our management presentation that tries to articulate what we've been saying now for some time, which is that we, studying all of the core data, and we've got cores from -- in excess of a dozen wells across the play now, is that we don't see anything other than fairly nuance differences between clay content, quartz content, calcite content. So we believe pretty strongly that the variability that we've seen across the play is really not being driven by geology and feel pretty comfortable and that's why we're moving the rig down onto the formerly Devon acreage right away is to demonstrate that point. So we still view the entire area that we have outlined in the red halo on our management presentation as perspective. And as Rob mentioned, we'll go about continuing delineation, as well as moving towards something a little bit closer towards development drilling and try to strike the right balances in terms of the capital allocation next year.

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

And as it relates to acreage position, I know there's quite a bit of overlap with you and Encana, it's starting to get to the point like in other plays, Wattenberg or Utica, where guys have swapped acreage around. As we look forward through 2014, is that a plan of yours to consolidate more acreage in yours and do some swaps with Encana and other operators in the area and really kind of core up your position. Or is it too early for that, in your opinion?

Walter G. Goodrich

Well, good question, Ron. In fact, very encouraging when you look at the Encana slides this morning and you look at their map in particular, you'll see very similar footprints to ours. And in particular, in the Mississippi core position. So -- which is basically why we've had a non-operated interest in some of their wells and they've had a non-operated interest in some of our wells. What we would like to do, and we think they may be receptive to this and that we've had some conversations, is to swap some acreage so that we can consolidate interest in our block, in our units, and frankly, it would wind up being basically kind of a checkerboard look because our footprints are very similar. But we think that makes a lot of sense and the initial response from Encana was that, that made some sense to them. So we're going to be getting with them in trying to do that swipe-like acreage and that makes some sense to us.

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

And then, just on the completion style between getting and having the pipe stuck in the Huff well and being unable to complete some of the -- or drill through some of the plugs. Can you just give us a little bit of an update in terms of the above versus below rubble zone, what you're seeing, do you think it's related to that or is it just the early phase of a new play where industry both you, E&P and the service guys, need to figure out the best way to get everything done since the rock is apparently giving the oil up?

Walter G. Goodrich

Yes, Ron. This is Gil. So I think we would say that, thus far, we see best drilling results, we've seen landing above, as Rob said, this Huff well would've been a record had it not been for the stuck drill pipe. In terms of stuck drill pipe, it happens in the business from time to time, we don't get overly concerned about 1-inch since it's a stuck drill pipe. We think that, that's something that we will certainly be addressing and do everything we can to mitigate in the future. We don't look at that as a systemic issue out here with quite a few wells drilled without having that particular problem. I think, you will continue to see us experiment with still some above and some below the rubble zone and continue to get up the learning curve. But we've certainly seeing some good wells recently. We've had very nice production performance landing above, so we're pretty comfortable with either of those 2 targets from a reservoir standpoint.

Operator

Your next question comes from the line of John Freeman with Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

On the ramp from 2 rigs to 5 rigs by the end of next year, can you give a little bit more color on the budget in terms of how you're planning to add those rigs, is it just linear throughout the year, is it more lumpy than that?

Robert C. Turnham

Yes, John, this is Rob. Well, first quarter of next year, you'll see the third rig, and then, when you are spreading those rigs out, mainly due to timing and desire on where to take the rig. So I think, it's going to be linear, but it's not going to be 30 days apart, so I would kind of stagger those out over the first, second and perhaps by the time you get to the third quarter, you can see us with the fifth rig. And as I said earlier, where we drill and what wells, what our working interest is, it's going to be a bit fluid, but the $300 million budget has us with 60% of our activity with 2/3 working interest and then 40% with 100% interest. And we've also allocated 5 gross, 1 net, well, non-operated position, in case we have small acreage in Encana or other operator units that we don't wind up swapping.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay. And then, on the discussion on moving in a few instances to pad drilling next year, which is earlier than I would have thought. In the past, you've talked more about maybe 2015. But on those initial ones, kind of just a general overview of what the scope of those 2-well, 3-well pads, just kind of where you're planning on doing those and kind of the scope of them?

Walter G. Goodrich

Yes. Really, John, what we technically are not doing is developmental drilling where you're drilling alternate unit wells in the same acreage block or the same unit. So where it makes sense it may be in an area where you have very blocky acreage that still needs to be captured by forming units and drilling wells, but you can access it from 1 pad. So hard to imagine drilling in 2014 or even 2015, more than 2 wells per pad, mainly because we're still going to be -- the primary focus is still going to be delineation and acreage capture, and that would still allow you to capture the acreage yet experience some of the cost savings from pad drilling. So I would say, latter half of 2014, you could see us drilling that. Now the Devon acreage that we bought, a lot of that is contiguous, big blocks, so it should be very acceptable to that strategy. Another thing that we're focused on and the good news is that we can perpetuate or hold about 241,000 net acres through 2018 by paying about $34 million worth of lease or rentals spread out over the next 3 years, so very manageable. I think the price per acre is about $144 an acre, so very manageable to maintain a big block of our acreage, and that's assuming that you don't drill any wells and capture any of that acreage during that period of time by forming units. So very manageable block. We're going to just gradually spread our wells out, de-risk the acreage, capture the acreage and drive our well cost down.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

A question on -- you're going to drill 3 wells on the recently acquired acreage, and we know about the -- you're going to drill the Weyerhaeuser. How far south are you going to test the acreage and maybe what depth are you all testing?

Walter G. Goodrich

Yes, Brian, this is Gil. We're not going terribly far south, we'll be a little south of the Mississippi/Louisiana border. We're not going to be testing what you would consider the very southern reaches of the play. And that really is pretty similar for all 3 of these wells that Rob described. If you look at our formally Devon acreage we acquired, it really is in kind of 3 fairly large chunky pieces, the Weyerhaeuser will be right in the middle of those. And we'll be -- that well is not going to be terribly deep, somewhere probably around 12,500 feet through vertical depth. We will then move, as Rob said, east, kind of in the northern center of the easternmost large position we acquired. Now that will likely be a little bit shallower there, it will probably be around 11,500. And then we'll move back to the west, probably near the original Devon Beech Grove well. That well will be slightly deeper, probably in the neighborhood of about 13,000 feet. So all fairly similar in terms of depth, just moving out a little bit geographically east and west.

Brian M. Corales - Howard Weil Incorporated, Research Division

Right. And then, I mean, obviously, Encana had the discussion today with the TMS, have you all talked to them in terms of -- I know you have some allocation for non-op -- for some non-op wells, and I know you're still trying to swap acreage. I mean, with the increase in rig count they're having, could you have more than maybe you originally thought from Encana-operated?

Walter G. Goodrich

That's potential, Brian. But as Rob said, we are in discussion with them about some sort of -- I don't know that it would be a global swap of acreage, but a swap of acreage where we both try to get away from having fairly small non-operated working interest in the other's wells. So we think that probably makes sense given our planned level of activities in there, we'll likely come up with some agreement. It may be on a well-by-well basis. In addition, I think, it's important to note that we've got a global joint operating agreement in place with Encana that covers all of our joint acreage out here. So to the extent one party for whatever reason might want to or not want to participate in any given well that 1 or 2 parties is proposing, we would have the opportunity to do that, both under the consent and nonconsent provisions of those operating agreements.

Operator

your next question comes from the line of Leo Mariani with RBC Capital.

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

I just wanted to get a little bit more clarity around some of the non-operated stuff here. Are you guys currently participating in any non-ops? And I guess, are there any that you think are on the near-term horizon here and any new operators that have recently shown up to play where you guys are having discussion?

Robert C. Turnham

Well, yes, we are seeing new operators in the play. To answer your last question, we expect 2 or 3 of them. Certainly 2 of them to potentially start talking about that, so we're aware of the files from assignments in the parish courthouse. And so I think that's a given, but we'll let them discuss it when they're ready to talk. As to currently participating as a non-operated working interest, we are not. We have seen probably 10 Encana units that are in progress, whether they've been approved or applied for, and it doesn't look like we're going to have any material interest in those units. We are aware of Sanchez, who's planning to drill some wells. We know Contango has filed for some permits. So far, we really don't have any acreage in those units that are specifically filed of record. But look, when you look at -- the core of the TMS is a fairly small area, if you compare that to the Eagle Ford. No question, the more operators that get in there, it's going to benefit our company tremendously, and we're likely to see units at least proposed an acreage swap opportunities so we'll just continue to have those discussions.

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

Okay. And I guess, in terms of a potential JV on your northern acreage, is there any kind of updated thoughts on the potential for that in 2014? Any thoughts on sort of timing?

Walter G. Goodrich

Yes, Leo. This is Gil. We continue to think of that as a 2014 event. We're pretty confident it won’t happen this year. Couldn't completely rule it out. We are going very slow. As we've said, our focus right now is first and foremost on delineation of the acreage, particularly the acreage we acquired from Devon this summer. So I think we're going to let that play out and then probably get a little bit more serious about it next year.

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

Okay. And I guess, just in terms of your budget, $300 million next year, are you guys -- what are you guys assuming for your average TMS well cost on that budget?

Robert C. Turnham

Leo, this is Rob. We're still using that $13 million AFE, when you add in facility cost, it certainly adds to that, but we're making a projection of $13.5 million-or-so with the facility and infrastructure spread out over a number of wells. So until we can exhibit and routinely see reduced well cost, which we think we'll have, we think it's prudent to build in the current estimates.

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

Well, and I guess, just with respect to kind of the rest of 2013 here, any kind of more granularity? I know you have your guidance out there for 30% or 40% oil growth, looks like you guys are more shying towards the low end. I mean, can you guys tighten that up all the fourth quarter, should we kind of expect low end for the year on oil or how should we think about it?

Walter G. Goodrich

Yes, Leo, this is Gil. We've made no change to the full year guidance. We might tighten up towards the low end. Now some of it depends on the timing. Rob was asked a question about timing on the Huff well in particular, hard to nail down an exact timeframe of that. So I think, timing more than anything else might influence where the fourth quarter volumes actually end up.

Operator

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

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

On the Huff well, you've been cleaning that out now for a few days, it sounds like. How confident are you that you won't have any wellbore integrity issues with that well when you go to run casing?

Walter G. Goodrich

Mike, this is Gil. So obviously, there is no absolute certainties in anything. But we have been going very slow and cautious by design to just make sure that we have a wellbore that's got full integrity. We have been seeing some small pieces of shale come back periodically in the cuttings, we're monitoring that very closely. But right now, I would say, we're getting very close to clean out to the end of the lateral. As Rob said, I think, a couple of days, we should have that done. We think we have a very good, solid, stable wellbore at this point, which we're highly confident if we were to choose to run in today, we can get the casing to bottom. But obviously, tomorrow is a new day, so we'll see what happens. But as we sit this morning, we feel very good about it.

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

Okay. Good. And on the -- I think, it was the Anderson 17 3 -- well, you mentioned in your release 5 of the last 6 wells tracking above your 600,000 curve, I think the 17 3 was the one that you saw some depletion on. Is there any worry there that you may be just draining big fractures with these wells or do you have data that suggests you're getting some matrix contribution as well?

Walter G. Goodrich

Yes, Mike, this is Gil. So we're not really concerned about just draining big fractures. First of all, the TMS, the fractures there are fairly small in size, but very densely spaced. So our view is, our best view is that the fairly small natural fractures are somewhere between 1 and 2 feet space apart from each other in occurrence, we think that's all due to the deposition environment and the maturity in oil generation process, which end up with this thing being highly over-pressured. The 17 3, as you know, was frac-ed at the same time as the 17 2. Those wells, however, did not come online at the same time, the 17 2 got a head start by approximately 1 week to 10 days of production. It saw a very high IP rate, so it's a little difficult for us to fully see exactly what happened on the 17 3, other than it was trending up while on a smaller and more appropriate in our view, choke size was trending up pretty close to heading towards 1,000 barrels a day. I think, we reported it at around between 800 and 900 barrels a day. And it was at that point that as we've said previously, Encana began to open the chokes for draw down so that it could run jet pumps on the well -- excuse me, ASPs. And so that well just we don't think is a great indication of what we've seen from the other wells recently. And if we could get to a more consistent pattern in terms of completion techniques and flowback techniques, we're very comfortable with where we're heading.

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

It sounds like the 17 2 well is hanging in pretty nicely, even though, as you mentioned, Encana did have an accelerated choke program there, does that give you any confidence to be more aggressive with your wells or are you comfortable with the way you're producing them?

Walter G. Goodrich

Sorry, Mike, this is Gil. No, that well fell off pretty hard. It has come back up and is looking pretty good and a bit flatter, but it did evolve pretty hard in terms of rate prior to getting it all pumped. So we continue to believe that until proven otherwise, bring these wells up, get them to a 14, 15, or 16, $0.64 choke, really letting the wells talk to us and then flowing it until it gets down to a point that it actually needs artificially we think is a better way to go.

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

Okay. And then, in terms of your 2014 drilling program, does Concordia Parish fit into that next year or no?

Walter G. Goodrich

We hope so. We have no definitive plan, but depending on industry activity works out, we can certainly see us drilling a well with Concordia, probably second half, Mike, of next year rather than first half. But we do want to see a delineation over there sometime in the course of 2014, could slip into 2015, but it's on our radar screen.

Operator

Your next question comes from the line of Steve Berman with Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

With all the excitement over at TMS, I hate to ask an Eagle Ford question, but I will. Can you just talk about some recent well results over there, how they're doing versus your historicals?

Robert C. Turnham

Yes, Steve, this is Rob. We'll continue to update our slide obviously. But I think what you saw in a reduced DD&A rate was very encouraging and that obviously our well results are improving and our costs are decreasing. And I think what we've said previously, I think, still holds true that when you get into this developmental drilling with proper completions and down spacing, we're seeing a bit flatter curves, not quite the same high initial rate, and that's reflected in our current presentation of our decline curve. So we don't see that changing a whole lot when we update that. But obviously, as I said, very encouraged that the third-party engineering reserves are certainly improving.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And I will ask one TMS question. You may have mentioned this. What was the intended lateral length on the Huff well versus the usable 5,400 feet?

Walter G. Goodrich

Well, we are then and going forward kind of targeting 6,000-foot laterals routinely. And frankly, we were pretty close to that before getting stuck and we had to back off of it. And so we lost a little bit of that -- of usable lateral by virtue of getting stuck. So I think, going forward, just routinely seeking out now if we can -- if we're making extremely good progress at 6,000 feet, you'll likely see us continue, but the minute your bit goes down and you have to trip to replace that past 6,000 feet, then we'll likely call it quits. So that's what we're routinely targeting is 6,000 feet or greater if it's going well.

Operator

Your next question comes from the line of Chad Mabry with MLV & Co.

Chad L. Mabry - MLV & Co LLC, Research Division

Just a quick follow-up on the TMS acreage news that slipped a little bit from about 320,000 to 300,000 net acres. Just curious where that acreage dropped off? And then, with the budget increase to cover your extension payments, where do you think you'll end the year there on the acreage side?

Robert C. Turnham

Yes. We certainly had some fringe acreage within the Devon block that did not have lease extensions, that we obviously didn't drill on and have not gone back to renew. So we're still well north of 300,000 acres, that's why we changed it to show 300,000 plus. We would expect, if it's a small lease in a remote area that we're better off served concentrating more on areas that we can control our own destiny and will have a material interest. But back to my previous remarks where we had 241,000 acres that actually have lease extensions or long terms, obviously, we're going to focus not only on delineation, but capturing acreage that does not have lease extensions that keeps our acreage position high. And until we see any reason to not renew or continue the thought of developing certain blocks, we're going to try to maintain that block as much as possible. But that's why we -- from line up quite a while back, changed that to north of 300,000 acres, because you could see some small tracks that fall off.

Chad L. Mabry - MLV & Co LLC, Research Division

Okay. That's helpful and it answers my next question on the 240. Okay. Just a quick follow-up, if I could. As far as modeling LOE going forward, how much workover activity should we expect over the next couple of quarters in the Eagle Ford?

Robert C. Turnham

I think, similar amounts. Really, a lot of that has to do with pumps and the artificial lift portion having to do some work, maybe cleanout work, that sort of thing. So I'm not sure you're going to see material differences.

Operator

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

Phillips Johnston - Capital One Securities, Inc., Research Division

Just wanted to ask about what 2014 production might look like, at least from a directional point of view, obviously, there's some push-pull between increasing activity in the TMS and scaling back activity in the Eagle Ford, which is obviously in more of a developed mode at this point, but just wondering if you have any early comments there?

Robert C. Turnham

Yes, Phillips, this is Rob. We tend to put out a press release after the first of the year that gives that guidance. But obviously, the rate of growth in the oil volumes is going to be greater than it is this year just by virtue of spending more money than what we did, and where we're drilling those wells are more prolific. I mean, our TMS wells, even though they take a little bit longer are close to twice as productive. So we'll put that updated guidance out after the first, but certainly, you can expect greater growth in '14 than what you see in '13 in oil volumes. Gas volumes just depends on kind of what level of activity and when we drill Angelina River Trend wells. We have no plans to drill North Louisiana, Haynesville wells, and obviously nothing in East Texas. So that's an Angelina River Trend. So not going to be material differences on our gas likely up or down, but we'll type that up in January.

Phillips Johnston - Capital One Securities, Inc., Research Division

Okay. And you mentioned the Angelina River Trend, obviously, that was a very good well drilled by an operator just to the west of your acreage. I was just wondering what sort of intel you sort of have on the completions process there?

Robert C. Turnham

Well, we are monitoring it for sure and we've been tracking that production for quite some time. I think, still, when you look at the use of our capital and the higher rates of return in the oil plays, we certainly would prefer to be drilling all better rates of return wells. But we do have a lease issue in the Angelina River Trend in which we need to currently drill 2.5 wells per year, which is why we put the $30 million allocation there. But clearly, that well, I believe, you're referring to, has made over 5 Bcf in 10 months and I think it's actually been updated to more than 6 Bcf in its first year. So that's obviously very prolific, but we're continuing to monitor that and schedule our capital in that area to maintain our leasehold block.

Operator

Your next question comes from the line of David Snow with Energy Equities Incorporated.

David Snow

Are you using submitted liners in either the Tuscaloosa or the Eagle Ford?

Walter G. Goodrich

No, everything we're doing got submitted liner, casing with perfect block.

David Snow

And then, laterals also?

Robert C. Turnham

Yes.

David Snow

Okay. And are you using a top drive to help you on those stuck incidents?

Walter G. Goodrich

Every rig we've got there have top drives on them.

Operator

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

I wanted to ask one kind of broad question and then one follow-up specific question. And the broad one is I noted with interest that you appear to be targeting prior Devon drilling to locate some of the targets that you're going to be drilling in 2014. So the broad question is what do you think are the really important improvements over your approach versus the prior Devon efforts that's going to produce better results drilling essentially in the same locations?

Walter G. Goodrich

Yes, this is Gil. So I would say that, primarily, it's on the completion side. We obviously have -- we and Encana have learned an awful lot over the last 18 to 24 months on drilling, and we've outlined those for you over time as best we can. I think, relative to the Devon acreage and the Devon acquisition opportunity, it's really about lateral links, interval stage links, primarily proper amounts, first stage, fluid types and clay stabilization. So we think those are the right recipes for success. As I said in my comments earlier to a question, we don't think geology is the principle driver here, we think it's really completion technique and lateral links. So we're in the process here with our first wells demonstrating that.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. Great. That was good color. And my other question was, I believe you mentioned earlier in the call today referring to zipper fracs as a cost saving item once you're getting independent drilling and developmental drilling. But we're also hearing a lot in the Eagle Ford and the Permian, other place, we're being led to think that zipper fracs are actually something that enhances EUR, breaking more rock and EUR increases. So does that potential exist in the TMS as well?

Robert C. Turnham

Absolutely, Jeff. That is a real benefit. You're obviously cross-stimulating when frac-ing the same stage in multiple wells in an area, you do see the benefit of that. So we expect potentially better EURs. And then well cost, clearly, when you're using the equipment, I think, our calculation has us using the equipment by about 40% less time. And part of your invoice from your pressure pumping company is obviously use of the equipment. So great opportunity to for us and the TMS capture acreage by drilling off of a pad and then realize these cost savings and potentially see better EURs.

Operator

Ladies and gentlemen, that will conclude today's question-and-answer portion of today's call. I will now turn the call back to Gil Goodrich for closing remarks.

Walter G. Goodrich

Thank you, Phil. Thank you, everyone, for participating. We appreciate it. We look forward to reporting our yearend financials to you first of next year. Thank you.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a good day.

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