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PetroQuest Energy, Inc. (NYSE:PQ)

Q2 2012 Earnings Call

August 2, 2012 9:30 AM ET

Executives

Matt Quantz – IR

Charles Goodson – Chairman, President and CEO

Bond Clement – EVP, CFO and Treasurer

Analysts

Will Green – Stephens

Andrew Coleman – Raymond James

Adam Lawlis – Simmons & Company

Richard Tullis – Capital One Southcoast

Don Crist – Johnson Rice

Tim Rezvan – Sterne Agee

Operator

Good morning, and welcome to the Petroquest Energy, Inc.’s Second Quarter 2012 Conference Call. (Operator Instructions) Please note that this event is being recorded. I would now like to turn the conference over to Matt Quantz. Please go ahead.

Matt Quantz

Good morning, everyone. We would like to welcome you to our second quarter conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Todd Zehnder, COO; and Bond Clement, CFO.

As you’ve come to expect, we would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding Petroquest business, which are not historical facts are forward-looking statements that involve risk and uncertainties. For a discussion of such risks and uncertainties which could cause the actual results to differ from those contained in the forward-looking statements, see Risk Factors in our annual and quarterly SEC filings, and in the forward-looking statements in our press release. We assume no obligation to update our forward-looking statements. Please also note that on today’s call we will be referring to non-GAAP financial measures, including discretionary cash flow. Historical non-GAAP financial measures are reconciled for the most directly comparable GAAP measures in our press release included in our Form 8-K filed with the SEC today.

With that, Charlie will get us started with an overview of the quarter.

Charles Goodson

Good morning. During the second quarter we produced 8.4 Bcfe or 92.4 million cubic feet of gas equivalent per day. The 92.4 million cubic feet of gas equivalent per day was comprised of approximately 76 million cubic feet of gas, 1,300 barrels of oil and 1,300 barrels of NGLs. Approximately 75% of our second quarter production came from our long life assets.

We now posted four consecutive quarters of sequential production growth as our total production is up 14% over the last 12 months, with our NGL production up 43% since June of 2011. As we continue to allocate capital to the Mississippian Lime and liquids rich assets we would expect to see similar growth rates in liquids over the ensuing 12 months. Revenues for the quarter were $33.4 million with product price realizations including hedges of $111 per barrel of oil and $2.23 per Mcf of gas. NGL product price realizations averaged $40 a barrel.

In our operations press release yesterday we announced a second significant discovery at La Cantera, the Broussard in stage #2. This well was drilled to a total depth of 19,150 feet and logged 310 feet of net pay in the Cris R massive main objective. The well also logged approximately 200 feet gross pay – probable pay in sands above and below the main reservoir. The Broussard at stage #2 is 190 feet higher on structure compared to the discovery well.

As a point of reference, the initial discovery well logged 248 feet of pay, and has accumed approximately 170,000 barrels of liquids and 3 Bcfe of gas in four months with virtually no pressure drop, quite a prolific reservoir. We believe that the entire La Cantera structure is larger than originally projected, and without question the most significant Gulf Coast discovery in the company’s 27-year history.

Our completion for the Broussard stage #2 well was designed to accommodate a 30% higher production rate than the Thibodeaux #1. Therefore, we’re expecting to commence production in mid-September at 2,000 barrels of liquids and 35 million cubic feet of gas per day.

At that time we’re expecting total gross daily production volumes from our La Cantera facilities of approximately 3,500 barrels of liquids and 65 million cubic feet of gas. In conjunction with our ongoing completion and production efforts, we’re evaluating the log and core date to determine if we have additional wells are needed to drain the expanded proven reserves and new pays. Based on what we have seen to date, we expect to drill a third well at La Cantera during 2013. This discovery could also set up additional drilling opportunities past 2013 as we develop this oil and gas field.

From 2007 through the end of 2012 our Gulf Coast assets have generated over $300 million of free cash flow. Our La Cantera and Thunder Bayou projects should significantly extend the life of this Gulf Coast revenue stream and provide significant additional free cash flow that we’ll leverage off of in our future resource expansion efforts.

Along with our La Cantera drilling activity, we have commenced 3D survey over our Thunder Bayou prospect, which is located approximately two miles north of La Cantera within the same regional structural complex and fault system. Today, gave an issue will provide additional imaging of the Thunder Bayou prospect, as well help to identify additional prospects in this prolific area.

Thunder Bayou is expected to spud during the second quarter of 2013, and we have an estimated 34% working interest in this high-impact project that is a gross pre-drill estimate of nearly 20 million barrels of oil equivalent. Assessing our near-term Gulf Coast inventory, we’ll be drilling a moderate-risk oil prospect in Lafourche Parish, Louisiana. The well has a composed total depth of 13,400 feet and gross un-risked reserve potential over 1 million barrels of oil. We have 22% working interest in this prospect that is expected to spud later this month.

Turning to the Arkoma Basin in Northern Oklahoma, in the Mississippian Lime, we have drilled five wells and have established production on two of the wells. The two wells are producing in Pawnee County and achieved 24-hour max rates of 320 BOE and 661 BOE with an average production mix of 76% oil. Both wells were completed using a specific frac design, which was tailored based on the various rock properties in encountered in the lateral. For example, PQ/ML #1 was a 4,100-foot lateral which had a 12-stage frac design. Stages 1 through 7 contained a pure white sand mix. Stages 8 to 11 was an acid to slick water design, and Stage 12 was a slick water-without-sand frac.

PQ/ML #2 was identical to PQ/ML #1 in both lateral length and number of frac stages performed. However, all 12 stages of this well were uniform and contained an acid to slick water mix. We’re providing this level of detail to help illustrate that we’re still in the early stages of the learning curve and are experimenting with various completion techniques and artificial lift options to optimize the ultimate recoveries.

In addition to our two producing wells, we have three additional wells that are in various stages of completion. One of these wells is a 4,037-foot lateral which encountered hot porous chat layer within the massive Mississippi line. This well, before this well, we’ve only completed one frac stage within a hot proxy interval to determine if this section could produce with limited simulation. The well is currently flowing back water and we’ll evaluate the production performance from this single-stage prior frac in the remainder of the lateral.

Again, we’re providing this level of detail to illustrate the variability in techniques that we’re applying our early wells as we work to optimize development. That being said, we’re very encouraged with the results from our initial wells from the eastern portion of our 27,000 net acre position, which we’ve exceeded our predrill expectations in terms of IP rates and of experience of shallower than forecasted initial decline.

We’re currently running two rigs, one in Pawnee and one in Kay. In addition to completing the five wells already drilled in Pawnee, for the remainder of this year we plan to drill an additional 10 to 15 wells of which roughly half will be in Pawnee and the remainder in Kay and Grant. We’re also planning on participating in two non-op wells in Grant County, including one that is currently drilling. We remain active on the leasing front as we’ve added an additional 2,600 net acres last month in Kay County, and have assembled a 56,000 gross acre position across four counties. While still early on our initial positive results on the extreme eastern portion of acreage have further strength in our confidence in its expanding oil trend, which has the ability to transform our oil production profile.

Now turning to the Woodford where we initiated production from seven additional Woodford liquids rich wells. This group of wells had an average lateral length of approximately 4,700 feet, and achieved an average maximum 24-hour gross rate of approximately 2,300 Mcf of gas and 350 barrels of NGLs per day with anticipated gross reserves of 619 MBOE per well. Since early April when MarkWest completed a 21-mile pipeline to connect our liquids rich area to their processing facilities, we have now grown our daily net Woodford NGL production from zero at March 31, 2012 to approximately 600 net barrels per day, which represents approximately 35% of our total NGL volumes.

It’s important to note that our Woodford NGLs are currently receiving Mont Belvieu pricing, and we did not experience any ethane rejection issues during the second quarter. With two rigs running, additional leasing activity ongoing and a joint venture structure enhancing our drilling economics, we expect continued growth from this high rate of return asset for the foreseeable future, even in its current gas price environment.

Regarding our joint venture, as of June 30, 2012 we have completed spending under Phase I, and estimate we have utilized approximately 4% of the $93 million Phase II drilling carry. Assuming our current activity in both the Mississippian Lime and liquids rich Woodford continues, we expect the drilling carry to last into the second half of 2014. However, we’ve continued strong results in the Mississippian Lime, the length of this carry could be extended if we and our partner elect to allocate more capital to the lower cost – well cost in Mississippian Lime.

In East Texas we recently completed our sixth operated horizontal Cotton Valley well. Our PQ/CVX #6 well was completed in E Berry member of the Cotton Valley and achieved a 24-hour match gross rate of 6 million cubic feet of gas and 504 barrels of NGLs. This is the second strongest horizontal Cotton Valley well we have drilled to date. Our most prolific well to date, PQ/CVX #1, IP’d at 7 million cubic feet of gas and 510 barrels of NGLs. And had a Ryder Scott calculated EUR of 1.2 million barrels of oil equivalent.

In addition, our PQ/CVX #7 well is waiting on completion. And our final well in the 2012 program, PQ/CVX #8, in which we have a 100% working interest, reached total depth last week. Both wells are expected to be completed this week, and will conclude our 2012 program. We’re excited about the results we’ve posted during 2012 where our average EUR to date has been approximately 800 MBOE. And we’re looking forward to next year’s program to continue to prove this virtually undeveloped liquids rich asset.

In the Eagle Ford shale, we have reached total depth on two additional wells in LaSalle County, which are both in the completion phase, and should be producing later this month. To date, we have participated in five Eagle Ford wells, which have achieved an average IP rate of approximately 500 BOE per day. We remain excited about this acreage position within the trend, and we’re currently evaluating initial drilling plans on both an operated and non-operated basis.

With that, I’ll turn it over to Bond to go over the financial results.

Bond Clement

Thanks, Charlie. Good morning, everyone. During the second quarter we recorded a net loss of $55 million or $0.87 per diluted share. And we generated discretionary cash flow of approximately $20 million. During the second quarter our trailing 12-month average natural gas price used to compute our 6 30 reserves declined by 16%, resulting in a non-cash ceiling test write down during the quarter of $53 million. Looking at the 2011 prices that will roll off of the trailing 12-month price calculations throughout the remainder of the year, additional impairments may occur during the third and fourth quarters.

During the quarter LOE totaled $9.1 million or $1.08 per Mcfe, which was lower than the range of our guidance, and down 6% sequentially. Our LOE costs continue to be positively impacted by our salt water systems in the Woodford. During June we completed our third salt water disposal system in the Woodford, this one on the far western side of our acreage position in our NGL rich area.

In addition during the quarter, our maintenance costs were lower than we had budgeted as we were able to defer some normal repair maintenance work until next year. G&A costs for the second quarter totaled $6 million and included $1.9 million of noncash stock comp. Overhead costs were in line with our original guidance. Interest expense during the second quarter totaled $2.4 million, which was also in line with our guidance. We capitalized $1.7 million of interest during the quarter. So in total, interest costs were $4.1 million.

During the second quarter the state of Oklahoma notified us that several of our wells drilled since 2009 in the Woodford have been approved for severance tax refunds. As a result, we recorded a $2.7 million receivable at June 30 to reflect the net refunds we expect to receive over the next 36 months. We expect our severance tax rate in the third quarter to return to normal levels as we are guiding $0.10 to $0.15 per round.

Looking at the balance sheet, during the quarter we invested $38 million in CapEx. The breakout of this capital is approximately $37 million of direct drilling CapEx, a credit of $3.8 million in acquisition costs, which reflect the $6 million sell-down in the Mississippian Lime that we reported in April, and $4.9 million of capitalized overhead and interest.

As noted in the release this morning, we did increase the range of our CapEx guidance to $110 million to $115 million. The slight increase from the previous midpoint of our guidance of $103 million was primarily due to the addition of costs associated with the oil-focused Gulf Coast well Charlie mentioned earlier, set to spud later this month; the acquisition of participating interest in an onshore Gulf Coast project to be drilled in 2013; additional leasing of both the liquids rich Woodford and Mississippian Lime areas; as well as the addition of seismic costs relative to a group 3D shoot we will participate in Kay County early next year.

While our spend during the first half of the year has totaled approximately 60% of our full year guidance, as previously stated, we continue to expect CapEx in the back half of the year to decline as our Cotton Valley, Eagle Ford and La Cantera spending will be ramping up during the third quarter.

To help bridge the gap between our CapEx and cash flow we’re continuing to pursue divestments of noncore assets in both the Fayetteville and the Niobrara. In the interim we will occasionally draw on our $125 million revolver for short-term working capital needs. With over $100 million of available borrowing capacity at June 30, combined with approximately $89 million of future drilling carry to leverage, and a growing liquids production base, we continue to maintain a substantial liquidity position.

Looking at guidance for the third quarter, our current plans for producing between 92 million and 97 million cubic feet per day, the midpoint of which would be up 2% sequentially and over 17% from the third quarter of 2011; for the full year we’re revising our production guidance upward for the second time this year to 92 million to 97 million cubic feet per day from our original 2012 guidance of 87 million to 92 million cubic feet per day. During the first half of 2012 NGL volumes comprised approximately 8% of total production.

For the full year we still expect to grow this percentage to 12% of total volumes. Using the midpoint of our full year guidance, this would imply a significant 80% growth in NGL production during 2012, primarily driven by our Woodford rich, horizontal Cotton Valley and La Cantera projects. While ethane and propane prices have experienced decline since the beginning of 2012, approximately one third of our total company blended NGL stream is comprised with a heavier WTI length products of normal butane, Iso Butane, the natural gasoline. As a result, our NGL pricing should be more resilient than many of our peers that have a higher percentage of their NGL stream tied to ethane and propane.

On the hedging front we recently executed our first gas hedge for 2013, as well as an additional gas hedge for the back half of 2012. For our 2013 hedge, we utilized a three-way structure for the first time where we’re able to sell a $2.00 put app option to increase the ceiling of our collar to over $4.00.

As many of you know from other producers that utilize this common hedge strategy, this structure does not qualify for hedge accounting treatment. So we will be recording a change in fair value of this hedge through the income statement, as reflected by the $375,000 noncash derivative charge we took during the second quarter. All of our other hedges will continue to be mark-to-mark through the balance sheet. We currently have approximately 500 barrels per day of oil and approximately 200 barrels of NGLs hedged for the remainder of this year, with average oil prices of $102.89 per barrel on oil and $91.26 per barrel on NGLs. In addition we now have approximately 8 Bcf gas hedged for the remainder of 2012 with an average floor of $3.13 per Mcf.

With that, I’ll turn it back to Charlie.

Charles Goodson

We’ve assembled an asset base that is 95% Petroquest operated, which gives us the flexibility and optionality to direct capital to exploit oil, NGLs or natural gas, depending on the commodity price cycles. Our Mississippian Lime and Gulf Coast assets provides us with a vehicle to grow oil production in the current environment where there is a large price disparity between oil and natural gas.

Our Cotton Valley and liquids rich Woodford assets have multiple years of NGL drilling inventory, which provides us with attractive rates of return and supports our ability to continue to grow in a low gas price environment. And finally, our best-in-class dry Woodford acreage, as well as our Fayetteville and Bossier assets will be flexible as gas prices continue to improve. This flexible asset base, along with our physically conservative philosophy, and $89 million in approximated future drilling carries has positioned our company to grow and prosper during one of the most challenging yet exciting periods this industry has experienced.

With that, we’ll now open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) The first question comes from Will Green of Stephens.

Will Green – Stephens

Good morning, guys.

Bond Clement

Good morning.

Charles Goodson

Hi, Will.

Will Green – Stephens

I wonder if we can start the Miss Lime. Do you guys have – how long have those been on? Do you have 30-day rates for both of those wells yet?

Bond Clement

Yeah. Will, the first well came on somewhat I’d say early June. So we do. We saw a 30-day rate right around 200 BOE per day on that well. The second one, the higher rate well just came on about two-and-a-half, three weeks ago. And we’ve seen to date around 525 BOE per day so far.

Will Green – Stephens

Great. Well, congrats on the first two then.

Bond Clement

Thank you.

Will Green – Stephens

And then you know what are you guys thinking about EURs? Is it too early? Or do you have an assumption yet on what those two wells at least will look like?

Bond Clement

You know this early in the life they’re obviously taking a guess at it is going to be pretty difficult. I’d say that these wells are clearly exceeding our predrill estimate, and what we approved all this space and activity on. So that’s the positive. And everything that we were proving was making money. So I think it’s too early for us to come out and say we think this is going to be the overall EUR. But I’d say that the IP rate was higher than we were expecting. And thus far, although very early, there’s a calling rate seen to be at or above our expectations.

Will Green – Stephens

Great. And then what is the – you know what’s the target well cost up there, the gross well cost you guys are going after?

Bond Clement

You know we’re targeting the low 3s, $3 million or the low 3s. We have any initial drilling in a basin. The first things we’re doing is experimenting with different things. We’re doing more and more science on these wells. We’re doing a lot more logging analysis than probably the next set of wells. And we – the drilling that we’ve done so far have been more chart versus chat, which is going to take a little bit longer to drill. And we’re optimizing bits and motors and everything that comes along with it. So I think we’ll get it down there. These have run more in the mid-3s. And so after we get our first 10 to 15 down, see how we’re going to put these into more of a repeatable process. Then we will aggressively focus on call for that point. But we’re no different than everybody else out there. And I would think that we’re going to get our well costs in line with the group you’ve seen so far.

Will Green – Stephens

Sure. Well, guys, I appreciate the color, and congrats on the quarter.

Bond Clement

Thanks, Will.

Charles Goodson

Thanks.

Operator

The next question comes from Andrew Coleman of Raymond James.

Andrew Coleman – Raymond James

Hey, good morning, folks, and thanks a lot.

Charles Goodson

Good morning.

Andrew Coleman – Raymond James

So, Charles, based on the success here you guys have had at La Cantera, I guess do you have a view as to what overall mix onshore versus offshore might trend to you over the next, you know, as you head into year-end?

Charles Goodson

Are you considering South Louisiana, are you asking Gulf Coast versus resource, or would you consider La Cantera onshore?

Andrew Coleman – Raymond James

I guess conventional versus unconventional.

Charles Goodson

Yes.

Andrew Coleman – Raymond James

Then I guess, if you could talk about just the cash flows coming from those as a mix.

Bond Clement

Right. I think what this – I think what La Cantera is going to is going to stabilize that production mix that about a quarter of our production is going to come from the Gulf Coast region and three quarters is going to come from long lives. And if you go back to 2004, 2005 when this whole transition started, we would have thought that that base would have been significantly smaller except for some rather large discoveries like La Cantera. So what it’s doing, it’s going to provide that base from a quarter of production. Reserves are down to probably 10%, would be my guess right now, being from the Gulf Coast.

But you’re getting on the point of how much cash flows arrive from these assets, and it somewhat ties in to what Charlie said, the free cash flows from that have pulled it off for the last several years, being $300 million. We’re going to continue to see that. And with the oil and gas prices and NGL prices like we’re seeing right now, my guess is being – scriptwriting, you’re going to look at the Gulf Coast producing probably 40% of your cash flow in the company, even though it’s about a quarter of the production. And the big drivers to this are going to be how aggressive we are able to get into the Mississippi line and drive that oil volume up. That’s obviously going to drive cash flow. So, all in all, very positive that we’re able to maintain this base, up 25% from the Gulf Coast with very limited capital going into that basin.

Charles Goodson

Yes. And put another way, we always struggle with this when the Gulf Coast represented over 50% of our reserves, where we always knew the reserves were higher but yet to produce into them. Now with about 10% of our reserves, it should let the R/P ratio to move up to a more reasonable level, eight or nine years, and we recognize that we’ll never be able to book all those reserves but we’ll be able to produce into them. So it’s a nicely-put proposition that we can manage it as it is. We’re stripping off a lot of cash flows to develop these long-life assets, as Todd said, but continue to be very opportunistic in drilling these type projects.

Andrew Coleman – Raymond James

Okay, good. And then I guess a second question, perhaps this is for Bond, can you – do you guys still have of those – the basis hedges? I can’t recall, on the Mid-Continent. And if so, how close is the Mid-Continent volume to getting above the threshold?

Bond Clement

We do still have that contract in place, and what you’re referring to is the $0.85 basis differential on the Woodford. That’s on our first $50 million of gross production. We are above that on a gross basis. So with every molecule that we produce above that threshold the contract is less penalistic to us. That contract does expire in October of 2013, Andrew, so we are still subject to that agreement.

Andrew Coleman – Raymond James

Okay. Then the last one is I guess, when you look at your NGL mix, rough percentages, how much of that would be coming from the Gulf Coast versus the on-shore stuff, the Woodford and Mississippian?

Bond Clement

You’re probably 50/50 right now. When you think about the Woodford coming on strong as it has since we brought on the northwest line at 35%, and you layer in Carthage and then with an additional Gulf Coast well in La Cantera #2 you’re going to be roughly 50/50 on your NGL mix on Gulf Coast and resource trends.

Andrew Coleman – Raymond James

Okay. So your average T&F OpEx line is in the ten cents per gallon?

Bond Clement

I’m sorry, what was that question?

Andrew Coleman – Raymond James

The transportation and fractionation cost, since you’ve got a mix – since they’re all going on the Mont Belvieu you’re going to get a much lower transportation cost coming from the Gulf Coast, so you’re...

Bond Clement

I think in general what you’re getting to is the T&F charges up in the longer life basins are a little higher than the Gulf Coast. Our split is going to be lower than what you would compare the peer group to. We want that number right in front of us. Maybe just give Matt a call right after and we can get you that detail.

Andrew Coleman – Raymond James

Perfect. Thank you. Appreciate the time today.

Charles Goodson

Sure.

Operator

The next question comes from Adam Lawlis from Simmons & Company.

Adam Lawlis – Simmons & Company

Morning, guys. Great quarter.

Charles Goodson

Thank you.

Adam Lawlis – Simmons & Company

Do you guys have an early read on estimate from the resource potential associated with La Cantera #2?

Bond Clement

Well, I would say that our booking came in a little bit above our pre-drill estimate which was over 50 BCF so the structure at this point has proven over 100 BCF booked to it. What would be incremental to that is, as Charlie mentioned, we’ve got 200 feet that we are considering probable pay – about half of that is in the lower part of the Cris R massive that we’re producing from, and then the other half is from sands above our current completion. We don’t have an estimate for that number yet, but I would say that thus far our group seems encouraged that the results so far are going to yield a higher EUR for that structure than originally booked. So I would say that the 100 Bcf has room to grow most likely.

Charles Goodson

And the more important aspect is that some of the zones that we saw in these additional paces are what we’re looking for at Thunder Bayou. And so it’s given us much more confidence that you know if we looked at Thunder Bayou and La Cantera in how they’re getting more and more comparable.

Adam Lawlis – Simmons & Company

That’s helpful. Thanks guys. And a follow-up, do you guys anticipate shifting more capital in the Miss Lime going forward given your well results? And what has to happen in order for you to put more capital to work in the play?

Bond Clement

Well thus far based on results I would say yes, we would likely allocate more capital to that trend. I don’t think it’s going to happen in the second half of this year. We’ve got our two rigs running, and we’ve learned that drilling these areas up, finding out the data from it and then going back with a more aggressive capital program is probably the most prudent way to do it. So I would expect that should we continue to get these type results 2013 we’ll have definitely a greater capital allocation to that. The second part to that obviously is how much our – we and our joint venture partner want to allocate the VAT region along with other ones. So we’ll be working with them based on the first half dozen results or so, and be putting that guidance out call it later this year.

Adam Lawlis – Simmons & Company

That’s great. Thanks. And so what is the timeline for completing these three additional Miss Lime wells? And when do you anticipate releasing those additional well results? Be a next quarter thing, or do you have any press releases?

Bond Clement

Well two of the wells are in flow back right now. Charlie mentioned one. We came into a mid-chat interval that had a very high velocity. So we’re treating that a little different. We fracked one space so far, and we’re evaluating whether we just go ahead and frac that entire 4,000-foot lateral. So it’s in a flow back. It still needs some completion work done after we’re done with this science project, if you will.

Another well is flowing back frac load right now and so we should be getting results on it. And the third well is actually in the second day of prep in fracking right now. That on top of we’ll probably complete another four wells by the end of this quarter I would think. We have one in Kay that we’ll be moving to next week. And I would think you probably have another three wells fracked this quarter, along with a pretty high interest, about 25% non-op interest over in Grant.

So you know I would assume that we would just put all those results out at the end of the quarter, maybe in some type of ops update or something. We’ve historically not been a well-by-well releaser, and we find that releasing these in groups is probably more beneficial for everybody. And so at this point while we haven’t made any decisions, I would assume at the end of the quarter or our next earnings release.

Adam Lawlis – Simmons & Company

Great. Thanks. And one final one real quick, what are you guys seeing on service costs across your onshore?

Bond Clement

I would say that they’re probably continuing to be more available and rates maybe are flat to soft a little bit. But we’re clearly having less trouble procuring certain services. And things feel a little bit better from our side of the business.

Adam Lawlis – Simmons & Company

Great. That’s all I have. Thanks, guys.

Operator

(Operator Instructions) The next question comes from Richard Tullis from Capital One Southcoast.

Richard Tullis – Capital One Southcoast

Thank you. Good morning. A lot of my question’s been covered already, but just a couple more. Charlie, I know a lot of other operators have seen a large volume of water coming out of the Miss Lime. What are you seeing so far? And how’s the handling of that going?

Charles Goodson

I think that’s what you get up here for is in getting an inch of water ahead. So yeah, we’re seeing certainly large volumes and our water disposal is something that’s going very well. It’s something that we live within the Gulf Coast. And so we transported that, you know the ability to understand how to get the water, produce it and get it back underground as fast as possible as efficiently and effectively as possible. And that’s job one up there, get ahead of your water. And so that’s gone very well. You know we are expanding the trend in the east, so a lot of facilities and a lot of things that you’d get in the more developed area, electricity and things like that, infrastructure we’re having to add ourselves. But it’s going very well.

Richard Tullis – Capital One Southcoast

Okay. What was the gross cost to drill the second La Cantera well?

Bond Clement

It was about $22 million to drill. And completion costs will probably be about I guess somewhere around $5 million or $6 million. And we’ve had the facility so all we have to do is run a line that we’re waiting on a permit right now. So I think all in you’re going to be looking at $26 million, $28 million buttoned up.

Richard Tullis – Capital One Southcoast

Okay. Thank you. That’s helpful.

Bond Clement

And just to put that – a number that we threw around yesterday, Richard, just to put a little scope on this, that facility in today’s gas price environment, that overall complex of two wells will probably start generating somewhere around $400,000 of revenue on the daily basis.

Richard Tullis – Capital One Southcoast

Okay.

Bond Clement

And while those numbers may not be found staggering to some, you can think about how much production and how much cash flow that facility will start throwing out once these two wells are both producing.

Richard Tullis – Capital One Southcoast

That’s a good point. And then lastly, what do you estimate the rate of return for say this latest East Texas Cotton Valley horizontal using the current gas and NGL pricing?

Bond Clement

Well, you know we’ve drilled these with the expectation that NGLs would be a little bit higher, but we also drilled them with the expectation that gas would be a little lower. So I would think somewhere in the mid-20s, 25%, 30% internal rate of return, assuming it holds up like it has been, which is pretty good for this pricing environment. And I think we would – with the predictability we have out there, we can continue to do that. The beautiful thing about Carthage is, is HBP, and we’re going to drill it as fast or as slow as we see fit.

Richard Tullis – Capital One Southcoast

Okay. Thank you. I appreciate it.

Operator

The next question comes from Don Crist of Johnson Rice.

Don Crist – Johnson Rice

Good morning.

Charles Goodson

Hello.

Operator

Your next question comes from Tim Rezvan of Sterne, Agee.

Tim Rezvan – Sterne Agee

Good morning, guys. I had a few quick ones for you. I noticed with the – you’re writing up about $17 million on the credit facility. Can we read into that that gives you more confidence in your kind of asset sales coming to fruition in the back half of this year?

Charles Goodson

You know, Tim, I think the borrowing today has just been a function of managing working capital needs. We’ve always been committed this year to getting those asset sales done. I’m not sure you could read into our work ethic relative to trying to get those assets hold relative to borrowing. So we continue to working that process hard and we’re committed to the process.

Tim Rezvan – Sterne Agee

Okay. So, no material update on any of the asset sales then? I know you mentioned something earlier but it wasn’t a lot of detail.

Charles Goodson

No, we’re still working both Niobrara, obviously we’re not as – we don’t have as much control over that process, but Fayetteville is still very active.

Bond Clement

Yeah, I think too, you know, the fact that we’ve been so successful in some of these projects is another indication we’re just not going to give away.

Tim Rezvan – Sterne Agee

Okay, okay. And second, on the commodity price side, if you look at the 2013, you see the strip roughly 3.73, 3.75. What would you look for to layer in additional hedges next year?

Bond Clement

We’ve always sort of taken the approach of stair-stepping our hedge position in place in order to dollar cost average our floors up, but the first position effectively a three by four cost of collar they put you roughly a 350 that you need to improve on that. So I think we, like probably a lot of others, will take a hard look at the strip for 2013 just above four, start layering in additional hedges.

Tim Rezvan – Sterne Agee

Okay. That’s helpful. And then I’d like to ask you, can you talk about the JV, maybe stretching that to the back half of 2014? So, just to clarify, if you were to transition more to the Mississippian Lime, you think that carry would extend farther out?

Bond Clement

That’s correct. I mean obviously with the well cost discrepancy between the Woodford and the Mississippian Lime, you’re using much less of the promote with a more focused Mississippian Lime program. So your carry would inherently last longer.

Tim Rezvan – Sterne Agee

Okay. Okay. And then I guess on a related note, I know it’s early in the Miss Lime, but how could you think about the rig ramps, assuming that you continue to have good results. How could we think like that into 2013 and beyond.

Bond Clement

I think, like Todd said, we’re going to finish up the program for the rest of this year, evaluate the results from more than two wells and then allocate capital accordingly working with our partner between the Miss Lime and the Woodford ridge.

Tim Rezvan – Sterne Agee

Okay. Thanks. That’s all I had.

Operator

(Operator Instructions) The next question comes from Don Crist from Johnson Rice. Your line is open, sir.

Don Crist – Johnson Rice

Hello?

Charles Goodson

Hello?

Don Crist – Johnson Rice

Hey, guys. Sorry about that. On Thunder Bayou, Charlie, I think you mentioned a second ago that some of the pays you’re targeting in Thunder Bayou may be what you saw either above or below the pays in La Cantera #2. Can you clarify that?

Charles Goodson

Yeah. The upper Cris section in the zones above the Cris are some of the ones that we’re targeting to the north field. We’re also targeting the Cris massive. So where we saw some shows down dip in wells on this structure, in shallow horizon, those are things that we’re targeting. So it becomes more of a multiple objective structure as opposed to a single objective. And the entire structure is simply a function of migrating faults from shallow production down to deeper production, you know, getting into a more detailed discussion about it. But as you look at something that comes multi-objective as opposed to single-objective, you’re more confident in your interpretation and the fact that you have much lower risk structure.

Don Crist – Johnson Rice

Okay. And you’re shooting 3D shortly. When do you expect to have that in hand? And I think you had talked about that as potentially being a mid-2013 drill. Is that still the right timeline?

Charles Goodson

I think we’re going to finish the 3D and probably have it in house at about year end.

Bond Clement

Yeah, probably late November or early December.

Charles Goodson

It’s a very large 3D. It covers a much larger area than just Thunder Bayou. It’s a group shoot and will give everybody involved in the shoot a really good portal into that entire structural complex. So we’re all very excited about it. But you know obviously our main focus is on anything that can help on the northern end of La Cantera, but more importantly Thunder Bayou.

Don Crist – Johnson Rice

Okay. Great. Everything else was asked earlier. Thank you, guys.

Charles Goodson

Thanks.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to the management for any closing remarks.

Charles Goodson

We’d like to thank everybody for their time and continued support. And hopefully we will see you guys at Intercom in a couple of weeks. Thank you.

Operator

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

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