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Executives

Matt Quantz - Manager, Investor Relations

Charles Goodson - Chairman, Chief Executive Officer, and President

Todd Zehnder - Chief Operating Officer

Bond Clement - Chief Financial Officer

Analysts

Will Green - Stephens

Dave Kistler - Simmons & Company

Joe Allman - JPMorgan

Ron Mills - Johnson Rice

PetroQuest Energy, Inc. (PQ) Q3 2012 Earnings Conference Call November 7, 2012 9:30 AM ET

Operator

Good morning, and welcome to the PetroQuest Energy, Inc. 2012 Third Quarter Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Mr. Matt Quantz, Manager of Investor Relations. Please go ahead, sir.

Matt Quantz - Manager, Investor Relations

Thank you. Good morning, everyone. We would like to welcome you to our third 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 to 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 - Chairman, Chief Executive Officer, and President

Good morning. During the third quarter, we produced 8.5 Bcfe or 92.6 million cubic feet of gas equivalent per day. The 92.6 million cubic feet equivalent per day was comprised of approximately 75 million cubic feet of gas, 1,300 barrels of oil and 1,600 barrels of NGLs. We now posted five consecutive quarters of sequential production growth as our total production is up 15% over the last 12 months, with our NGL production up 53% since the quarter ended September 2011.

Revenues for the quarter were $34 million with product price realizations including hedges of $108 per barrel of oil and $2.26 per Mcf of gas. NGL product price realizations averaged $34 per barrel.

Now, moving to operations, in our operations update press release last week, we announced that we have recently established production from our second well at La Cantera, the Broussard Estates #2. As you will recall, logged 310 feet of pay in the Cris R2 and has another 200 feet of potential pay above the Cris R2. This well is currently flowing at a pipeline restricted growth daily rate of 800 barrels of oil, 1700 barrels of NGLs in 37 million cubic feet of gas.

We are stalling downstream pipeline compression equipment to alleviate the takeaway capacity issues from this area and we expect our La Cantera field will be flowing in an unrestricted gross daily rate of approximately 1500 barrels of oil, 3100 barrels of NGLs and 70 million cubic feet of gas per day around year end. At the end of third quarter, our third-party reserve engineers book our first two wells at a combined 105 Bcfe of growth proved reserves, with estimated gross discounted pre-tax cash flows of $264 million. This project without question is one of the most impactful discoveries in our history and is one of the largest onshore Gulf Coast discoveries in the past 10 years. What's really exciting about this project is that it continues to grow.

After evaluating production data, logs and sidewall cores of the Thibodeaux #1 and the Broussard Estates #2 wells above the Cris R2 we are working with our partners in planning a third well, the Broussard Estates #3 in the first quarter of 2013. This well is projected to cost approximately 60% less than the first two wells as we expect to be able to sidetrack out of an existing wellbore. The well will target 200 feet of potential pay sands encountered in both the Thibodeaux #1 and Broussard Estates #2 wells above the Cris R2 and will accelerate production from the Crris R2 section encountered in the aforementioned wells by approximately five years.

Moving two miles in the north of La Cantera to our Thunder Bayou prospect where our 3D seismic data is expected to be delivered in approximately two months. Once this data is received we will use the enhanced imaging to determine the optimal drilling location to help us to identify additional prospects that could exist within this prolific basin. We believe that the Thunder Bayou prospect could turn out to replicate the success of our La Cantera discovery when considering we have a substantially larger working interest in this prospect. If successful, we would anticipate Thunder Bayou would also require multiple wells to properly develop the structure. Therefore it’s conceivable that if we had success in north that our La Cantera and Thunder Bayou projects could be producing in excess of 200 million cubic feet gross equivalent per day within a couple of a years. Focusing on the impact of PQ we would eclipse the highest Gulf Coast, Gulf of Mexico reserve reduction base which dates back when our focus was 100% on this basin. When these types of projects are successful they substantially increase our cash flow, production and reserves and in turn create significant shareholder value by no asset in our portfolio.

Turning to the Arkoma Basin in Northern Oklahoma, in the Mississippian Lime, we have established max 24-hour production rates on two new wells in Pawnee County, PQ/ML #5 and PQ/ML #7. These wells achieved maximum daily rates of 451 BOE and 227 BOE respectively with an average 70% oil production mix. In addition we’ve recently completed two wells in Kay County and one non-operating well in Grant County. Our Kay County wells are in early stages of flow back and our non-operating well in Grant County has just begun producing oil but it’s not had sufficient time to establish maximum rate.

As disclosed in our operations update press release last week, our PQ/ML #3 and #4 wells have produced large volumes of water and have not established consistent daily oil rates. We are in the process of attempting to isolate certain perforated intervals that could be in communication with water bearing Arbuckle zone in order to mitigate the high water production and establish consistent oil production. In all we’re encouraged by the early results to-date as wells we have established consistent production have realized an average initial rate of 415 BOE per day which is higher than we originally modeled during our pre-acquisition economic run. In addition, on wells where we have over 30 days of production and the average is 270 Boe per day over the 30 day period.

We believe that our Mississippi Lime program will follow the same path as out early Woodford program where it took 20 to 30 wells before we developed an ideal drilling plan and frac design. In the Woodford we continued to see steady improvement as we have now drilled approximately 120 wells. With that said carbonate reservoirs are different than shale reservoirs and wells will tend to have a significantly wider set of production thus economic results. With our joint venture promote we have an advantageous cost structure that allows us to generate attractive rates of return even as we are in R&D stage of our Mississippi Lime program.

Now turning to the Woodford, we initiated production from eight additional liquids rich Woodford wells this quarter. This group of wells had an average lateral length of approximately 4800 feet and achieved an average maximum 24-hour gross rate of approximately 2000 Mcf per day and 250 barrels of NGLs per day. With this type of NGL yield Mount Bellevue pricing and joint venture promote our liquids rich Woodford program is currently generating 80 plus percent rates of return. In addition we have five liquids rich Woodford wells that will be completed during the fourth quarter. We have posted solid production growth from our Woodford assets, which is up 23% since September of 2011. And we expect this growth trend to continue for the foreseeable future.

Turning to our joint venture as of September 30, 2012 we have utilized approximately 16% of the $93 million of Phase II drilling carry leaving us with approximately $78 million. Assuming our current activity in both the Mississippi Lime and liquids rich Woodford continues, we expect the drilling carry to last into the second quarter of 2014. Moving into East Texas where we have recently completed our seventh and eight operated horizontal Cotton Valley wells, our PQ/CVX #7 well had a 3800 foot lateral and was completed in the E Berry member of the Cotton Valley. This well achieved the 24-hour max gross rate of 6.4 million cubic feet of gas and 440 barrels of NGLs. This is the second best horizontal Cotton Valley wells we have drilled to-date and it is one of the strongest wells drilled in the – this evolving trend.

Our PQ #8 well experienced a mechanical issue that resulted in a shorter completed lateral of approximately 2800 feet. Even given the shorter length, the well still achieved a respectable 24-hour max rate of 3.6 million cubic feet of gas per day, again 280 barrels of NGLs. It’s important once again to point out our Carthage NGL production mix has approximately 20% natural gasoline, which effectively received WTI pricing.

Since the third quarter of 2011, we have increased our Carthage production by an impressive 68%. This asset provides us with another low-risk vehicle to substantially grow our liquids production. We are excited about next year's drilling program, where we expect to continue to post these best-in-class results. Lastly, moving back to Gulf Coast, where in addition to La Cantera and Thunder Bayou activity, we have several near-term moderate risk liquids-rich prospects. Our (overlay) prospect is an onshore South Louisiana oil prospect with a gross un-risk reserve potential of 1 million barrels of oil. We have an approximately 22% working interest in this well, which is expected to begin drilling later this month.

Next step will be Sawgrass prospect also located onshore in South Louisiana. This well has a gross un-risk reserve potential of 2 million barrels of oil equivalent. And we’ll spud during the first half of 2013. We have an approximate 35% working interest in this well and PetroQuest will be the operator. We continue adding to our already deep Gulf Coast inventory, and we’ll continue to look forward this asset for a stable liquids production and the excess free cash flow that it generates.

With that, I’ll turn it over to Bond.

Bond Clement - Chief Financial Officer

Thanks, Charlie. During the quarter, we’ve recorded a net loss of $38.6 million or $0.62 per diluted share. We generated discretionary cash flow of approximately $17 million. During the third quarter, our trailing 12-month average natural gas price used to compute our 9 30 reserves declined by 10% from the previous quarter, resulting in a non-cash ceiling test write down during the quarter of $35.4 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 fourth quarter, but are not expected to be significant. During the quarter, our LOE totaled $9.7 million or $1.13 per Mcfe, which was in the range of our guidance.

G&A costs for the third quarter totaled $6 million and included $1.8 million of non-cash stock comp expenses. Overhead costs were also in line with our guidance. Interest expense during the third quarter totaled $2.3 million. We capitalized $1.9 million of interest during the quarter bringing total interest cost of $4.2 million.

Looking at the balance sheet, during the quarter, we invested $42.7 million in capital expenditures. The breakout of this CapEx is approximately $32 million of direct CapEx, $5 million in additional leasing costs, and $5 million of capitalized overhead and the interest. Through the first nine months of 2012, our capital spend has totaled approximately $115 million. As noted in the release this morning, we did increase the range of our CapEx guidance to $130 million to $135 million, which would imply our fourth quarter CapEx of approximately $20 million or 50% down from third quarter spending.

Our original 2012 guidance was net of the budgeted sale of certain non-producing infrastructure assets that we have been working on and assume will be realized in 2012. To-date, this asset sale has not been closed, so we are effectively grossing up our CapEx guidance by the proceeds we were assuming in our original net CapEx guidance. Additional costs in 2012 from our previous guidance include some incremental leasing in and around our La Cantera prospect area as well as additional leasing on the western side of our Woodford acreage to increase our inventory of liquids-rich growing opportunities. To help bridge the gap between our CapEx and cash flow, we are continuing to pursue divestitures of non-core assets in the Fayetteville and Niobrara as well as the infrastructure assets that were previously projected to be sold in 2012.

In the interim, we will occasionally drill on our recently increased $130 million revolver for short-term working capital needs. As always, because we operate the vast majority of our activities, we have the ability to adjust our capital expenditures quickly in order to balance our spending with cash flow. We are going to get guidance for the fourth quarter. Our current plans call for producing between 94 million and 98 million cubic feet equivalent per day, the midpoint of which would be up 4% sequentially and over 10% from the fourth quarter of 2011.

During the first nine months of 2012, NGL volumes comprised 9% of total production. For the fourth quarter, we expect to grow this percentage to 14% of total volumes. Using the midpoint of our fourth quarter guidance, this would imply a 50% plus 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 declines since the beginning of the year, approximately one-third of our total company blended NGL stream is comprised with a heavier WTI length products of normal butanes, Iso Butanes, and natural gasolines. As a result, our NGL pricing should continue to be more resilient than many of our peers that have a higher percentage of their NGL stream tied to ethane and propane.

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

Charles Goodson - Chairman, Chief Executive Officer, and President

Thank you. We are excited about our numerous near-term catalysts that are starting up in the next couple of months. The third well La Cantera and our initial drill at Thunder Bayou are potential gamer-changers for this company. If successful, we should see another meaningful increased reduction and cash flow, which should allow us to continue to grow our resource assets base and increase Gulf Coast free cash flow. Our record in Gulf Coast speaks for itself, as others left we just improved. From 2007 through 2011, we deployed $267 million in capital to these assets, or roughly 29% of our total capital spent during this period.

In return, our Gulf Coast assets threw off a staggering $547 million in cash flow, which was reinvested back into growing our resource program. This strategy has allowed us to post compounded annual growth rates in production reserves of 28%, while for the most part staying away from capital markets. We are looking forward to continuing to execute this uniquely successful strategy and believe it provides us with the best model to create shareholder value through the various commodity price cycles in this industry.

With that, I’ll turn it back to Matt.

Matt Quantz - Manager, Investor Relations

Yes, operator, we are ready to take Q&A at this time.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) The first question will come from Will Green of Stephens. Please go ahead.

Will Green – Stephens

Hi, guys.

Charles Goodson

Good morning.

Bond Clement

Hello.

Will Green – Stephens

I wonder if you guys could give us a little bit of extra color on those, the two recent Miss Lime wells, you have seen a lot of water, is there anything that you changed in the completion technique, how far away are those from the other wells that have been successful and just any additional color there would be great?

Todd Zehnder

Okay, Will. It's Todd. I'll address them as two separate wells, real quick. The first one, if you guys remember on the last conference call, one of the wells we had encountered a different type of chart section, it was a high porosity chart interval that was rather unexpected, I guess for part of the lateral. But we were encouraged because of the good porosity that we have encountered. What it appears is that structurally we have probably tied into some water at that part of the lateral. So, our current plans are to try to isolate that part of the section and see if we can complete the more chart interval that is more prominent in the Pawnee County. The other well is rather close to some of our other wells. It was drilled in a chart section and appears to just be flowing a higher water cut. While we have seen some oil flowing back on it, it just is dominated by the water, so what we are trying to figure out and remediate is whether we frack down into a water bearing section be it the Arbuckle or something else, maybe down some type of fault plane and it's just a different animal than the forest one. So, while we didn’t expect to add wells like this, we expected a wide variability of wells and we are just dealing with it as we gain them.

Will Green – Stephens

Alright. I appreciate that. And can you remind us how long did the first few wells flow back water or that much water?

Todd Zehnder

Well, they are very different. They all flow back a little bit different some of them, some of them it takes – the first day you'll get oil on and some of them, it will take as long as 30 to 45 days. I believe the first day the first well took us somewhere around 23 days, if I remember correctly 23, 25 days. We've had them as long as 40 probably in our program that has made first oil.

Will Green – Stephens

Got you. And then I wonder if you guys could discuss gas, natural gas has had a decent rally, how are you guys thinking about kind of capital allocation going forward Miss Lime versus Woodford versus Cotton Valley? And then you guys thinking about or actually placing in hedges at this point, how are you thinking about all those kinds of issues?

Todd Zehnder

Right. As it relates to 2013, I think the initial capital budget is probably most dominated by the Gulf Coast and the Woodford still skewing over to the liquids rich because we do like Bond said on the call we do benefit from some heaviers up there that are giving us some good uplift. And obviously we are still concerned about where the gas price is because it has a lot of gas in it. So, with that said, I think that as we sit here and we’re working on 2013 program, I think those of the two areas that will receive the most capital. However, we are also going to continue to develop the Miss Lime we’re going – we have been saying this is kind of the exploratory phase. We’re looking for the good pockets that are going to have repeatable results. So, we’re going to continue to develop that asset and find some good areas.

And then the Cotton Valley we’ve just got the same type of program laid out for next year which is, it’s a great asset, we’re having very predictable results outside of one shorter lateral just due to some casing issues, but its still a good well. We feel very comfortable about the asset. I think more than anything this year’s drilling program expanded our inventory out there. It’s generating very good rates of return. But as you all know the Cotton Valley asset is all held by production and it is not being drilled on a promoted deal structure. So, it loses out because of that unfortunately even though we’re very, very pleased with the economics. As it relates to the hedging we are – we have not layered anything else in. We do – we’ve been watching the ’13 $4 or $4.05 handle, and I would tell you that we’re getting very close to getting I guess another part of our program put away, but the recent pullback has delayed that a little bit.

Will Green – Stephens

Got you. Well, I appreciate that. And then one another one what’s kind of the – are you guys still looking at other plays exploring other options for new plays. And with that said what’s the comfort level on the debt side either on the debt to EBITDA or debt to cap measure if you guys do look to go and lease in another play?

Todd Zehnder

Well, let’s say in general well we look at any trends. But our focus is clearly coming back to our core areas at this point. And we feel like we can grow this company predominately with additional opportunities in the Gulf Coast and Oklahoma. And just starting to extend East Texas has growth opportunities but we’ve got such a good asset base there with some of the opportunities that we have an – as aggressively we looked for opportunities in that region. I think you’re seeing – take a serious look at monetizing non-core assets be in the Fayetteville and the Niobrara and we have publicly stated that the Eagle Ford is not a core area for us and we have not grown that to a size where it’s going to be a core area. So, I wouldn’t be surprised if we made a decision to monetize those assets as well. I think that in turn will clean up some of any issues that you could have from a debt perspective. And if we were going into a new area, if it is an acreage type venture I don’t think you would see as do a big debt deal. I think that acreage is more of a – generated out of the either your internally generated cash flows or some alternative financing or some joint venture opportunity and then drill those wells. But if it is a producing acquisition in one of our core areas we feel comfortable putting more debt on it at that time, but we just haven’t – we haven’t made that big producing asset acquisition that I can reference you to.

Will Green – Stephens

Got you. So if you guys see something you can’t pass up its likely going to be funded through a non-core monetization or some sort of promoted structure right.

Todd Zehnder

Yes that’s correct. And I would tell you that our focus of where we’re looking the core areas are getting the lion share of our time and we’ll continue to do that.

Will Green – Stephens

Got you. Well, guys I really appreciate all the color. Thanks again.

Charles Goodson

Thanks, Will.

Operator

Our next question will come from Dave Kistler of Simmons & Company. Please go ahead.

Dave Kistler – Simmons & Company

Good morning guys.

Charles Goodson

Good morning, Dave.

Dave Kistler – Simmons & Company

Real quickly with respect to La Cantera as a whole in your decision to go ahead and move forward with this third well next year, can you talk about based on the pressures you’ll see in flow back, what kind of changes we might be seeing in terms of resource potential there?

Todd Zehnder

Well, the pressure of that really no – really very minimal pressure decline. So and we would expect that with this size structure and ultimately having water support at some point we wouldn’t expect to see a big pressure decline. I think more than anything what we need to do and what we’re working on with our own internal mapping and our reservoir engineers or third-party reservoir engineers is ultimately what does the structure look like and using 3D and we’re getting new data. We’ve reprocessed some data we’re getting part of the structure is actually going to get plumbed in from the (indiscernible). So, I don’t think the pressure data is necessarily going tell of that immediately but we’ve got other pieces of information that are ultimately tying in to what Charlie said on the call which is the resource, the resource numbers continue to get larger. We can’t quantify it yet Dave because work is ongoing and we will wait to see what our third-party engineers comeback within hopefully that number be forthcoming here sometime in fourth quarter.

Charles Goodson

And I think that we are – both wells are producing from the same reservoirs and which is nice, that your – we feel like on communication just range from a very large area, but we simply have lowest num gas.

Dave Kistler – Simmons & Company

Great, great. Well, that’s a helpful color there. And then maybe switching over to the Miss Lime, can you talk a little bit about what you’re thinking for well costs and has the recent activity in terms of what happened with the few wells that had interactive with water leading you guys to put more science to work there and should we be thinking about higher well cost or are really no deviation?

Charles Goodson

I think in general our initial set of wells will have more science and we will have higher well cost. It will not be as a result of what we’ve seen in these two wells. We are clearly doing a lot of coring and extensive logging and just early in trends I think differentiation of fracs between wells, differentiation of fracs between stages of wells. So, I clearly would say this is not our efficient part of the drilling program and we can look back on any other trends we’ve gotten into and this is not the time where us trying – I mean we always want to be cost efficient. But right now we want figure out what is the repeatable action for us then to go drive cost down.

But we’re doing now with the exploratory phase its trying to test different zones within the Mississippi line with different frac stages in different areas. So, there is a lot of moving parts and pieces. And we are still confident we’re going find some areas that are going have wells, well results that are maybe more along the lines of expectations of what the street is looking for. But if you look at the majority of our wells they are exceeding from an IP rate standpoint and as the declines work their way down. We’re hoping that they will exceed what we originally guided for this strength for and then ultimately our goal will be to increase those results.

Bond Clement

And also the lower costs we are sharing a data with number of companies that will have excess to lot of data that will lower our cost and that were not paying for data.

Dave Kistler – Simmons & Company

Great, that’s helpful. And then maybe just kind a following up on your comments of how capital might be allocated next year, can you talk about or just rank the place based on rate of return and I’m assuming that’s how you’re allocating the capital for next year?

Charles Goodson

Well, I think everybody understands that on a risk basis, there is no basin that at least and that and were involve and that we can speak to that competes with the Gulf Coast and its going continue to get especially with what we have going on real close to home and the predictability and getting the data that we have, we’re going to be allocating capital to that region. I think what we’re doing over on the Western side of the Woodford is probably got be from the set – rate of return standpoint. The second highest returns that we’re seeing because the liquids rich were driving costs down in that region, we are probably the most active operator I guess at this point in the trend. So, we’re having some cost efficiencies as a result of that and it’s a lower pressure shallower region that just hasn’t had liquids yet. So, I think from well cost standpoint we’re driving costs down there and will get great recoveries and a little bit of improvement in gas prices that were seeing. It probably comes in second. Then I guess then from that standpoint the East Texas assets would be the next ones. What I didn’t mention is the Miss Lime because we are still in the early phase of saying what is the rate of return ultimately going be on a predictable basis, we’re going to continue putting capital and work there to develop our data set and be able to come out and say where does that rank amongst the other plays after we’ve drilled some 10 to 15 wells.

Dave Kistler – Simmons & Company

Great, that’s helpful, I appreciate it. If you want – if you give any color on the specific rates if return that will be helpful?

Charles Goodson

We’ll have to get back you on that because obviously it’s going to be commodity price driven.

Dave Kistler – Simmons & Company

Yeah, okay. I appreciate it guys. Thank you very much.

Charles Goodson

Thank you, Dave.

Operator

And our next question will be from Joe Allman of JPMorgan. Please go ahead.

Joe Allman – JPMorgan

Thank you. Hi everybody.

Charles Goodson

Good morning Joe.

Bond Clement

Good morning Joe.

Joe Allman – JPMorgan

If you drill that re-entry well at La Cantera and what kind of bump up in value do you get, I know in your operations update you said the gross PB #10 is $264 million, so have you calculated what kind of bump up in value you get by accelerating the production?

Charles Goodson

We have Joe and it’s too – I guess there is too much variability in the results for us to close that. First of all we probably don’t put exploratory PB – or even gulf coast PB #10 is not exploratory but Gulf Coast PB #10 accretion, I can tell you a couple of things. The first thing is it’s going to accrete PB #10 because you’re going to be bringing an upper sand re-completions that will be happening seven years down the road. You’re going to accelerate that, so your PB basis on that alone will be significant.

The secondary part of that is the upper zone plus I’ll call it the lower (indiscernible) one which is unproven at this point because we have – we do not have it booked as proved reserve. Those will have the potential to have significant reserve enhancement and so what I am saying there is the upper most lobe of the proven section could double or triple in size over time because of the producing into a quality of the reserve. And then ultimately as we move up hole and recomplete, you will add proved reserves in that operation. So, kind of a confusing answer, but it’s hard for me to say that it goes from 260,000 million to X hundred million just as a result of this. There are some different factors, what I can tell you is the rate of return expectations are clearly much higher for this project than anything else we have in our inventory.

Joe Allman – JPMorgan

Okay, it’s helpful. And then in your Ops update you indicated gross reserves at 105 Bcfe at September 30, what did you have booked on a gross basis as of year end ’11?

Charles Goodson

I think it was right around 50 Bcfe. I think we’ve basically doubled the size of the overall structure with this second well.

Joe Allman – JPMorgan

Okay and it’s great. And then just one last one on, so the spending for 2013 can you just talk about that a little bit again I know you haven’t finalized everything, but the allocation is going to be most heavy to where I think you said Gulf Coast and the second is where and third is where?

Charles Goodson

Well, I’m not sure what’s going to be most heavy for the Gulf Coast I would say that the Gulf Coast and Oklahoma are going to be the most heavily allocated. And we have not finalized CapEx budget by any means. We really haven’t worked on that with our Board of Directors in a significant way. But I would say those two areas will get the most of it with East Texas being the third.

Joe Allman – JPMorgan

Okay and then slightly if they got. And just one last one, sorry, in terms of asset sales, give us a list of what you’re looking to sell and your expected timing?

Charles Goodson

Well we’ve been discussing the Fayetteville assets with several different parties ongoing throughout the year, so that would probably be the first one that we would execute on. And then in the Eagle Ford we have not started showing that data set yet. We finished drilling our program this year had those well basically all flowing back and we’re getting them on to be able to show sustained production that will be first quarter probably start showing that next year. And then those are the major ones that have I would say pretty significant capital ramification.

Joe Allman – JPMorgan

Okay, great guys. Thank you very much.

Charles Goodson

Sure. Thanks.

Operator

(Operator Instructions) The next question will come from Ron Mills of Johnson Rice. Please go ahead.

Ron Mills – Johnson Rice

Good morning.

Charles Goodson

Good morning.

Ron Mills – Johnson Rice

Question – just to follow-up on Joe’s last question the infrastructure assets that Bond talked about that you may look to sell where are those located?

Charles Goodson

They are throughout Oklahoma.

Ron Mills – Johnson Rice

And what’s the potential timing on that, it sounds like you have expected to get done this year but now it sounds like it may slip into next year is that…?

Bond Clement

Yeah that’s exactly right Ron. We had expected to sell those this year and we’re continuing to pursue that potential. But at this point but at this point we don’t feel comfortable that it’s going to happen this year if it does happen at all and so we just decided to obviously with only a couple of months left in the year to come out and just put the CapEx back and or takeaway the net out.

Ron Mills – Johnson Rice

Okay. And then looking at the Mississippi Lime you’ve had – you’ve discussed the results well but when we look forward you’ve kind of hop-scotched even around your Pawnee County area. When you look at 2013, how should we think about your development program in the Mississippi Lime in terms of both on the operated and to the extent that you have since this non-operated program as you continue to evaluate that opportunity?

Charles Goodson

Well, they in general, most – everything we are going to be doing up there is going to be operated for the most part. I mean, we'll have one or two like we have one this year, where it was non-operated. I would say from an operated perspective which you will see is we are going to go into Grant County later this year. We are going to move one of the rigs over to Grant and start testing that area. And I think we'll just finish moving around between K and probably a couple of more spread out throughout Pawnee. We are clearly seeing some areas that are having more predictable results, and we are also having I guess the good fortune of some pretty significant players moving around us in both of these areas, all three of them, in fact, Pawnee, K, and Grant. So, while the eastern side of the trend had the majority of the rigs going there for a while, I think you are starting to see some of the rigs move north obviously in the Kansas and coming over to the east, excuse me, I have said, the east, the western side of the trend originally had them. Some of those rigs are coming east and we are seeing some larger players start allocating some capital to nearby. So, I think between that and our drilling programs we are going to be able to see some, I guess, pocket that will probably further develop and go from there.

Ron Mills – Johnson Rice

Okay. And obviously, you are still, the pipeline issues have been mainly resolve at La Cantera, you are looking to expand that capacity to flow the first two wells at an unrestricted rate. But when you look to drilling the third well at La Cantera and/or the Thunder Bayou well, the first half of next year, what are your thoughts or what are you doing on the facility side to be able to handle the kind of NGL production uplift that you could see from those?

Charles Goodson

Well, there is a few different things. We got to have the pipeline infrastructure. We got to make sure the processing at third-party plants is there, and then we have our own field infrastructure. Obviously, Tigre Lagoon is going to be a completely separate field, which will take separate facility. So, that from a PetroQuest operated standpoint will just be our internal business. We are working with pipelines to make sure that we can get the gas to market, which is not going to be a problem. We have been working that ahead of time whether it's for a third well or Tigre Lagoon, we are well ahead of all those options. And then ultimately the processing, legacy Gulf Coast assets have plenty of processing capabilities. We are just working through the early innings of making sure with these big reservoirs working the best deal possible in making sure that ultimately we are making long-term decisions that affect a lot of value obviously when you are talking about hundreds of BCF of ultimate processing.

Ron Mills – Johnson Rice

Okay. And I think this is probably a follow-on to someone else's question as well, but when you look at 2013 and you go through your budgeting process, the next month or so, is it safe to assume that from a discipline standpoint, you guys are still going to be directionally looking to be more internally funded at a cash flow and have the cash flows really be the regulator on your CapEx, or has that changed?

Charles Goodson

Absolutely. Yes, the answer is yes absolutely. And we like all, I guess most of our gas peers are expecting a better gas price next year, so that will drive increased cash flow in our opinion.

Ron Mills – Johnson Rice

Alright. Well, I'll let someone else jump in. Thanks guys.

Charles Goodson

Thanks Ron.

Bond Clement

Thank you, Ron.

Operator

And at this time showing no additional questions in the queue, this will conclude our question-and-answer session. I would like to turn the conference back over to Matt Quantz for his closing remarks.

Matt Quantz - Manager, Investor Relations

Yes, we'd like to thank everybody for their time this morning and continued support.

Operator

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your line.

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