Penn Virginia Corporation
Q3 2013 Earnings Call Transcript

Published: 31 Oct 2013

[Operator:]

Good day ladies and gentlemen, and welcome to the Penn Virginia Corporation Third Quarter 2013 Conference Call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this call is being recorded. I would now like to introduce your host for today’s conference President and CEO, Baird Whitehead, please go ahead sir.

[Baird Whitehead:]

All right, thank you, Danielle. I would like to welcome you to Penn Virginia’s third quarter 2013 conference call. I am joined today by members of our team, including John Brooks, our Executive VP of Operations; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO, and Jim Dean, our Vice President of Corporate Development. Prior to getting started, we would like to remind you that the language in our forward-looking statement sections of the press release as well as our Form 10-Q, which were both filed last night, will apply to our comments this morning. In the third quarter operating cash flows and margins remain strong as a result of our ongoing growth or production we referred as well as lower unit operating costs. Some of the financial highlights for the third quarter include product revenues of $122 million, or about $67 per barrel equivalent, which is an increase of 11% from the second quarter. Oil and natural gas liquid revenues that were 15% higher than the second quarter and represented 89% of our product revenues. Oil [indiscernible] was 83% of our third product revenues. Operating margin of approximately $51 per barrel equivalent, an increase of 10% over the second quarter. Operating income which excludes the $132 million of an impairment expense of approximately $24 million, an increase of 336% over the second quarter. Adjusted EBITDAX of approximately $88 million, an increase of 6% over the second quarter and lastly adjusted net income loss of $1.5 million or $0.02 per diluted share compared to an adjusted net loss of $10.9 million for the second quarter or $0.17 per diluted share. So you can see we’ve made progress in every category I just went through. While production and revenues did increase in the third quarter, the increase was less than we had expected due almost solely to lower than expected reduction from a non-operated Eagle Ford Shale activity. This was caused by drilling issues which in turn caused delays in completions. The outside operated [ph] subsequently drop the rig which caused further variances in the third quarter production. As a result we reacted as quickly as we could and increased our operated drilling rig count by essentially one. It is now expected we will utilize a five rig drilling program during 2014 and we have assumed one rig outside operated program. Clearly the increase in operated activity for the remainder of this year will have a negligible production and cash flow effects during the fourth quarter as we continue with our pad drilling program. However, more substantial benefit will occur during the first quarter 2014. With a total of six rig program assumed for all of 2014 it is expected oil production will grow between 65% and 85% year-over-year and 40% to 70% for the fourth quarter ’13 to the fourth quarter 2014. In addition we recently completed our mid-year reserve evaluation. The proved reserves in Eagle Ford alone almost double from 26 million barrels equivalent at year end 2012 to about 51 million barrels to mid-year this year. The proved develop portion of the Eagle Ford alone increased from 9.7 million barrels at year end ’12 to 19.8 million barrels at mid-year. And which really is a scorecard of Eagle Ford Shale 3P reserves which includes the probable and possible on top of the proved that are now about 170 million barrels. If you remember pro forma of Magnum Hunter we had estimated about a 140 million barrel so within a very short period of time, we’ve been able to increase our 3P reserves in Eagle Ford by about 30 million barrels or an increase of 21%. We continue to aggressively grow the value of this asset as we down space in net acreage. We now have approximately 107,000 gross acres, 67 net acres in this play. We recently added about 5,000 net contiguous acres to our existing position since our last call in early August at a cost of about $1,600 an acre and as new acres opportunities continue to develop we recently decided to go ahead and add $11 million for lease acquisition in this fourth quarter as we expect to add up to another 7,000 contiguous net acres. This should bring our total by the end of the year to about 74,000 net acres. I think I’ve received a question Neal Dingmann in last quarter call ultimately where we wanted to be acreage wise and I said at that time about a 100,000 net acres. Based on this recent success we think this goal remains very much intact and very achievable and we think we should be able to continue to add acreage to $1,600 per acre clip. As at the end of the third quarter with the 67,000 net acres in hand, we estimate now that we have about 890 remaining drilling locations in our inventory. This represents a drilling inventory of about 10 years with a six week program which is an increase of about 20% from our previously announced inventory estimate of about 750 locations. And as we continue to increase acreage further, this inventory of course will only increase and could increase significantly from the current 890 estimate. And of course as this inventory increases, 3P reserves increased, the company increases so it's pretty clear while we’re pretty excited about what we’re doing in Eagle Ford right now with this low cost acreage addition. Not only we are increasing reserves, but just as important the value of those reserves is increasing as we continue to lower well cost and increase individual well productivity. John Brooks will give you some additional details on both those issues later during the call. In conjunction with the immediate reserve report, the borrowing base under our revolving credit facility was recently increased from $315 million to $425 million as a result to financial liquidity as of September 30 with approximately $330 million as compared to about $300 million as of June 30. As we have stated and will continue to state, it remains our intent over the next three years to self fund our capital program along with our credit facility and growing cash flows, we have also considered investing of some noncore assets as we have said. The sale of these assets would help supplement and fund the [indiscernible] over the next few years. We did put our pipeline up for bid that we had enhanced that is the Eagle Ford gas gathering and gas lit system. There was a tremendous amount of interest in both of these systems. We have received the bids which are currently being evaluated but bid based on what we have received a few of these bids have exceeded our minimum expectation. We are marching down the path to negotiate with that – with the hot bidder and we still expect to have that transaction closed by the end of this year or early in 2014. In addition, we will consider to sell some of our gas assets during the first half of 2014. We will also sell the rights to construct an old gathering system in Eagle Ford and we hope to get this package out to market by late this year or early 2014. The proceeds of any and all of these asset sales will improve our liquidity further and allow us to accelerate production and cash flow growth and at the same time reduce our debt to EBITDAX of the 2.5x going into 2016. So with that I would like to turn this over to Steve so he can provide an update of our financial progress.

[Steven A. Hartman:]

Okay. Thanks Baird and good morning. I will start the financial review and as we do in the earnings release, I will be comparing our third quarter results with the second quarter. Product revenues for the quarter were $121.6 million, or $63.33 per BOE, up 11% over the second quarter. The increase was driven by 7% increase in product pricing and 3% increase in production. Revenue from oil sales top $100 million this quarter for the first time ever and that’s 16% higher oil revenue than last quarter. Operating expenses were $29.7 million for the quarter or $16.47 per BOE which was $600,000 higher than the second quarter adjusted for acquisition cost. But 1% lower out of per barrel basis. The lease operating expense was 5% lower on a per barrel basis at $4.68 per barrel down from $4.94 in the second quarter. In general, we saw declines in LOE cost across the board with the exception of some higher downhaul repair costs, gathering, processing and transportation expense was relatively flat at a $1.68 per BOE. Production and ad valorem tax was lower than the previous quarter due to receipt of some severance tax refunds this quarter related to prior year activity. G&A expense excluding non-cash share base and liability base incentive compensation was $10.6 million or $5.85 per BOE up $400,000 from the second quarter due to some onetime employee related expense items and without those onetime costs recurring G&A would have been about $300,000 or less this quarter than the second quarter. Operating margins is described in our earning release, increased by $4.77 per BOE or 10% over the last quarter to $50.86 per BOE. This increase was driven as it has been for the last several quarters by a very strong operating margin in Eagle Ford which was about $75 per barrel in the third quarter excluding allocated G&A. Adjusted EBITDAX and non-GAAP measure reconciled on page 10 of the release was another company record at $88.3 million for the quarter and that is an increase of 6% over the last quarter. For our non-cash expenses, we recorded an impairment of $132.2 million which wrote down the carrying value of our Granite Wash asset by $121.8 million, Marcellus by $9.5 million and [indiscernible] by about a million. Our DD&A expense decreased to $34.57 per BOE down from $36.80 and our expiration expense was lowered by $4 million due to lower unproved property amortization for the Eagle Ford asset. Our net loss attributable to common shareholders for the quarter which includes the effect of the impairment and deducts $1.7 million of preferred stock dividends paid was $100.6 million or $1.54 per share. Adjusting for the impairment, another customary adjustments reconciled on page 10 of the release our adjusted net loss attributable to common shareholders was $1.5 million or $0.2 per share. This is the $0.15 per share improvement over the last quarter. We are pleased we’re making significant progress toward profitability and expect to be net income positive by 2014. Capital expenditures for the quarter were $120 million down $25 million from last quarter. The lower capital spending was primarily due to overall drilling and completion cost which John will discuss in more details shortly. We also had lower spending on seismic facilities construction. And moving on to capital resources and liquidity, at quarter end we had $128 million outstanding on the credit facility and $38 million of cash on the balance sheet. Our borrowing base at the end of the quarter was $350 million giving us financial liquidity of $257 million net of 11% credit. On Monday earlier this week as Baird already mentioned, we closed our new credit facility borrowing base of $425 million which is $75 million increase over our sparring with determination and $25 million higher than we had been guiding to in our last call. Pro forma for the borrowing base increased. Our liquidity at the quarter end was $332 million. Our leverage at quarter end was 3.6x total debt of pro forma adjusted EBITDAX compared to our credit facility covenant of 4.5x. Pro forma adjusted EBITDAX which includes the $45 million pro forma cash flow adjustment related to the Eagle Ford acquisition as permitted in our credit facility is $340 million for the trailing 12-month period. Moving on to hedges, we have been actively adding hedges to our portfolio for 2014 and 2015 and we look to protect $90 WTI price and keep as much upside where we can. We currently have 9,400 barrels per day of oil hedge for the remainder of 2013 which is 79% of the midpoint guidance at a weighted average flow of $94.69 per barrel. We have 8,500 barrels per day hedged for 2014 which is rough half of the midpoint of our oil production guidance with the weighted average flow of $93.49 per barrel. We started layering 2015 hedges this quarter and have 2,500 barrels per day hedged for the year at a weighted average flow of $91.74. Our current hedge position is summarized on page 12 of the release. Now looking at 2013 guidance update which is detailed on page 11 of the release, the main drivers of the change in the fourth quarter and full year 2013 guidance are the shortfall of production from outside operated Eagle Ford program along with the resulting financial impacts as Baird mentioned, adding a rig to make up for some of that volume loss and adding land dollar for our lease acquisition program. Production is expected to be 1.8 to 2 million barrels of oil equivalent for the fourth quarter which equates to 19,200 to 22,200 BOE per day. For full year 2013 this would be a 6.8 to 7 million BOE with which is about 250,000 barrels lower than the mid-point of our previous guidance. That change is essentially equal to the effect of the outside operated program under performance in the third quarter plus its effect rolling through the fourth quarter. We still expect to see about 6% total production growth and 15% growth in oil production in the fourth quarter over the third quarter even with these adjustments. Production revenue guidance was decreased on the slightly for 2013 to a range of $432 million to $449 million which implies fourth quarter revenue of $118 million to $135 million. Revenue guidance remain relative stable since the effect of lower volume was mostly offset by stronger product pricing in the third quarter. We lowered our midpoint of our full year 2013 lease operating expense by $0.62 per barrel based on our positive experience in the third quarter. That implies fourth quarter LOE of $5.58 to $5.70 per barrel. Gathering, processing and transportation expense was slightly higher due to the higher gas volumes contributed from the Lavaca county program. Recurring G&A was revised slightly lower to a midpoint run rate of $9.9 million for the fourth quarter. Unproved property amortization which is the primary component of expiration expense was revised downward to reflect a change in the accounting treatment for how we amortize unproved property in Eagle Ford essentially going forward we are just going to move land cost over to wells as they are drilled and we won’t amortize land cost expiration expense. DD&A was also revised lower on a unit basis because of higher than anticipated proved reserve adds in the mid year reserve report. For adjusted EBITDAX removing the midpoint for full year 2013 lowered by $4 million to account for the effects of lower production in the higher onetime employee related cost in the third quarter I already mentioned. We now expect full year adjusted EBITDAX of $321 million to $332 million. This implies the range of 89 to 100 million for the fourth quarter. After midpoint, this will be the 7% increase over the third quarter. Our capital expenditure guidance is now $500 million to $ 530 million which implies fourth quarter CapEx of $139 million to $169 million. This adds $20 million of drilling to completion to allow for the addition of the operated rig. It also increases the land budget by $11 million as Baird mentioned. Our fourth quarter guidance for additional land adds is now $14 million to $18 million. On the balance sheet, we are now guiding the year end total debt of $1.26 billion to $1.27 billion. This implies a credit facility balance of $185 million to $195 million under our current borrowing base of $425 million, we would have year end liquidity of about $250 million and this would further imply year end leverage of about 3.5x with pro forma adjusted EBITDAX for leverage calculation purposes in $26 million higher than our guidance. This year revolver balance range does not include any proceeds from the sale of our Eagle Ford gas gathering system with the sale of that asset by year end we would expect a dollar for dollar pick up in liquidity since we don’t lose any borrowing base value with the sale of that asset and a year end leverage ratio of around 3.3x. We expect therefore that after the sale of the gas gathering system, our liquidity going to 2014 would be in the neighborhood of $300 million to $340 million. Moving into 2014, we have some preliminary guidance to offer, we’ll provide our full 2014 guidance in February as we usually do. As Baird mentioned we expect to run a five rig operated programs for the entire year and we assume a one rig program operated by a partner with pretty much all the capital invested in Eagle Ford development. Our preliminary capital guidance for the program for 2014 is $510 million to $540 million and this assumes we complete the sale of the gas gathering system and any changes that we would make to facilities costs. Our preliminary guidance with total production volume is 9 million to 10 million BOE or 24,600 to 27,400 BOE per day. This would be a 30% to 45% increase over the midpoint of 2013 guidance. Crude oil production is expected to increase 65% to 85% over the midpoint of 2013 guidance and that implies 2014 oil production of 5.8 to 6.5 million barrels of oil equivalent. Our growth in the year end oil production exit rates which we are defining as fourth quarter ’14 oil production over fourth quarter ’13 oil production is expected to be 40% to 70% growth. And we expect this program to be fully funded with a liquidity we have on hand going into 2014, we expect to fund the program with cash flow from operations, proceeds from the Eagle Ford gas gathering system, proceeds from non-core asset sales and increases to our borrowing base. Now, although it is difficult at this point to estimate when our borrowing base increases will be and what the asset sale proceeds will be. We feel comfortable saying that we expect to maintain at least $200 million of liquidity through 2014. Now, we expect our leverage at the end of the year will be around 3.0x even without any non-core asset sales beyond the gas gathering system. So with that I would like to pass this off to John for our ops update.

[John A. Brooks:]

Thanks Steve and good morning. As Baird mentioned, in the third quarter our production and asset basis increase and we continue to have success in the Eagle Ford Shale. Touching upon some of the recent operational highlights, our third quarter production was 1.8 million barrels of oil equivalent or 19,638 BOE per day, up 2% from the second quarter. And in the third quarter Eagle Ford shale production accounted for 12,489 BOE per day and 9% sequential increase. We had record quarterly oil production of 10,373 barrels of oil per day, a 10% sequential increase. Oil and NGL volumes were 67% of total volumes in the third quarter compared to 64% in the prior quarter. Oil production was 53% of production during the third quarter compared to 49% in the second quarter. Despite this growth our production was somewhat less than expected during the third quarter due primarily to less than anticipated outside operated Eagle Ford Shale Production as Baird mentioned. Currently we have a 158 Eagle Ford Shale producing wells. We have 10 operated wells completing or waiting on completion and six operated wells being drilled. Average gross IP for the 18 most recent full-length operated wells was 1,288 BOE per day. In the initial 30 day average gross production rate for 15 of those 18 wells with the 30 day production history was 874 BOE per day. The average lateral links for these 18 wells was approximately 5,900 feet with an average of just over 24 frac stages. In general, the higher rates can be attributed to longer lateral links, therefore more frac stages, but also we believe were getting to see the advantages associated with pad drilling and closer well spacing, which improves induce track efficiencies and therefore overall production rates. 16 of our recently drilled wells were drilled off of six multiwell pads or roughly three wells per pad on average. Effective nominal spacing on these six pads average 73 acres. The closer spacing and use of zipper fracs appears to be working well. In addition, we used an average of £1,168 of profit per foot of lateral since midyear 2013. This compares to an average of approximately £915 of profit per foot for the wells completed previously. And we believe that increasing this frac intensity improves our productivity per stage with nominal increase in cost. Going forward since much of our legacy acreage is now held by production will continue our development program, focusing more on pad drilling and tighter spacing. Our average total well cost on a curve frac stages basis, including drilling and completion costs was approximately 350,000 in the third quarter of 2013, compared to approximately 430,000 in the second quarter of ’13, which is a 19% reduction in cost. The average stimulation cost per frac stage was approximately 110,000 in the third quarter of 2013, compared to approximately 150,000 in the second quarter, which is a 26% reduction. This decrease is not only attributable to contractual changes which are substantial, but also due to the continued evolution or stimulation design. Now this includes going to hybrid track design, which minimizes gel requirement, as well as reduced potential formation damage, increasing our sand concentrations up to £4 per gallon, we are at the formation tank and on a quicker ramp which reduces water, chemical and pump times. Using a hundred mess on the frontend to improve overall fracture complexity and replacing the more expensive ceramic product with a resin coat on the palin, which not only reduces the cost but also reduces or eliminates profit flow back while providing the advantage of higher closures stress. Our stimulation design continues to evolve as we more tightly engineer our fluids and pumping schedule, a further increase the malaprop pump for the lateral while keeping incremental cost low, and when we do all of that on the multiwell pad the completion efficiencies just multiply. On the drilling side additional efficiency gains are realized from pad drilling and whenever possible, we are using smaller spudder rigs to preset surface casing on multiwell pads. This is further enhanced by utilizing a walking rig that after setting production casing can quickly move over to the next well, further driving down our spud, the rig release portion of the overall cycle time by about two days per well and saves about $75,000 per well. Using the drilling pad is also complimented by use of the Rotary Steerable directional tools which we have been using, which deliver better wellbores and increased rig penetration further saving, over $200,000 well. And all of that all adds up to three straight quarters of declining well cost with longer laterals and more frac stages. In the third quarter, we drilled and completed 16 wells with average total well cost right below $8 million. We recently added an operated rig in an attempt to mitigate the fact that our partners and are non operated acreage released to rig in a third quarter. And as we’ve already mentioned, this step will have little production benefit in the fourth quarter of ’13, with most of the benefit being realized in the first quarter of ’14. During the fourth quarter of ’13, we plan to spud 25 gross and 17.1 net wells in the Eagle Ford, bringing our 2013 estimated total spuds to 71 gross and 45 net Eagle Ford Wells. As a result, fourth quarter 13 production is expected to be approximately 19,300 to 22,300 BOE per day. Over the next two years, we expect to continue to drill approximately 90 gross, Eagle Ford Wells per year. Assuming an ongoing six week program, five of which would be operated rigs. If our non-operator led down the remaining rig, we can all probability, we would add a six operated rig to offset the reduction in activity. Sequential quarterly production growth in 2014, beyond the first quarter could be lump year, due to an increased emphasis on pad drilling and the fact that the spud sales cycle times on a three well pad, could be up to 120 days. Additionally, existing offset wells will need to be shut in during completion operations. A new item of business forces that we have implemented, a comprehensive water resources management program to provide water resources for our Eagle Ford Shale asset development over the long term. We begun drilling deeper water wells that should yield significant volumes of non-potable water that we can then blend with treated produced water, treated flow back water and freshwater water from surface impoundments and significantly reduced volumes of fresh water from subsurface sources. From our business perspective, we think it's imperative to secure the necessary water to drill and complete the wells in our 890 and growing location inventory but also to do it in a manner that reflects continued commitment to good stewardship of increasingly scarce water resources in the environment as a whole. The upfront capital cost to achieve these goals are substantial, but over the tenure, plus life of the project should be minimal on a per well basis. Also, by treating our flow back water and much of our produced water, that would ordinarily be trucked off and pump down disposal well. We should be able to reclaim those water volumes to reuse at a cost that is competitive with merely disposing of them. Lastly, we remain enthusiastic with potential of all the upper Eagle Ford Shale enrolled in December, we will spud a two well exploratory test of the upper Eagle Ford in well, in the southern portion of our Lavaca County acreage. As a follow-up to our successful five stick, number one well, in the northeastern portion of our Lavaca County acreage. If this task works in terms of producing economically as well as separately from the lower Eagle Ford Shale, we will likely conduct a joint five well pad test of both the lower and upper Eagle Ford Shale, during 2014. If production from both zones is ultimately successful, this potential to add significantly to our drilling inventory. So, with that, I will turn it back to you Baird.

[Baird Whitehead:]

All right. Thanks John. Danielle, you already go ahead and take any questions, please.

[Operator:]

Thank you. (Operator Instructions) And our first question comes from Brian Corales from Howard Weil. Your line is now open.

[Brian Corales:]

Good morning guys and congratulations. The new inventory numbers you put out. Does that include the recently acquired 7,000 acres?

[Baird Whitehead:]

Well, the 7,000 acres were currently securing at in this fourth quarter but it does not include a 7,000 acres. No.

[Brian Corales:]

Okay and then two other questions. One on – you all talked about 75 acre spacing is kind of what you are going towards. Have you all tested anything tighter than that? Or do you plan to test anything even tighter than the 70, 75 acres?

[Baird Whitehead:]

Yes. It just happened to work out that way this quarter, Brian, I mean. You know, we are taking some wells, correct me if I am wrong, John. But we are taking some wells, down to about 400 feet, I think the actual numbers like 375 feet between lateral here soon. That will probably be around 45 acres or so, so, yes, I mean, there are some wells that are bigger, some wells are less than 73, but we continue to drive those lateral distances down. John, do you have anything to add to that, John?

[John A. Brooks:]

Yes. I would just say that 73 acres was an average of during the quarter. And both of those were 61 acres spacing, most of them between 400 and 500 foot lateral spacing between wells and as Baird alluded to we will be having a 375 foot lateral spacing test upcoming here in the near future.

[Brian Corales:]

Okay. Good that's helpful. And on the upper Eagle Ford, is that something that's present through most of your acreage, all your acreage and I remember the first well maybe being like 75% of an average Eagle Ford well. Do you have expectations right now of kind of in EU or comparison to what you drilling in the Eagle Ford?

[Baird Whitehead:]

Brian, as far as over what part of our acres this thing exist. We have an map based on well control, we have, I mean, we have a vertical wells we drill to get open whole information on the lower Eagle Ford in general, we think it's probably over half and two thirds of our acres, what we think is perspective, it's highly calcareous, is compared to lower Eagle Ford. As far as reserves go, I mean, we only have the one data point at this time, based on fitness at upper Eagle Ford, based on atrocities that over a – upper Eagle Ford, based on the open whole information that we do have, in the logging information we have. I mean, you could, if they are separate, you could, you know, metrically come up with the numbers that's pretty similar to with the lower Eagle Ford is on a per well basis.

[Brian Corales:]

All right guys. Thank you.

[Operator:]

Thank you and our next question comes from Welles Fitzpatrick from Johnson Rice. Please go ahead.

[Welles Fitzpatrick:]

Good morning. On the upper lower Eagle Ford test, are the – is this new one, is it going to be stacked directly or is it going to be modestly offset, implying kind of Chevron design, I guess, how far part of they are going to be, or those well boards going to be vertically and horizontally?

[John A. Brooks:]

Yes. They are not going to be stacked vertically, they will be offset somewhat, we are still in the process of permitting those wells, I can't give you the exact footage, but they will probably be in the order of maybe 500, 600 hundred feet apart in the plan view.

[Welles Fitzpatrick:]

Okay. And then, is the placement going to be any different, the placement or the completion going to be any different from yours initial, Eagle Ford Well, which if I remember correctly, it was completed pretty much the same as a lower.

[John A. Brooks:]

I think it will be essentially the same, the one difference, we are getting into an area that is deeper, higher pressure and hotter, so you know, we will be adjusting our fluid designs accordingly. But the ideas of still to get the same amount of sand per foot or more placed.

[Welles Fitzpatrick:]

Okay. Perfect. And then, just to kind of cover all those basis, the drilling issue that you are non partner had those, the affairs says those are mechanical in nature and had nothing to do with the rock.

[John A. Brooks:]

Yes, I think you know, that's a fair statement. I mean, the two wells, they are drilling two wells on the two well pad right now and after they finish these two wells. All of the jointly held acreage that we have within will be HBP'd. So I think that maybe driving their decision at some part. But you know, we were little bit further up the learning curve and they are in this area. We have drilled over 100 wells and they drilled, maybe 30 so. There is a learning curve involved.

[Welles Fitzpatrick:]

Okay, perfect. That's all I have. Congrats.

[Operator:]

Thank you. And our next question comes from Steve Berman from Canaccord Genuity, please go ahead.

[Steve Berman:]

Hi, good morning everyone. Let me follow up on Welles’ question, on any chance you could take over operator ship from -- as far as the JV goes, I mean, you are obviously doing a better job than they are?

[Baird Whitehead:]

That's a – it's a very difficult question to answer. I think at this time, we continue to talk to him, continue to have ongoing operation meetings to try to share information back-and-forth to help them on the drilling completions side but at this point of time I think it will be premature, for us to make any assumption, we could take over operation. That's all it's a very difficult challenge.

[Steve Berman:]

Understood, John, you mentioned heading into 2014, there might be some choppiness, quarter-to-quarter due to pad drilling. Did you see any of that in Q3 impacting the production or was the short from on the all side wall, all the non ops stuff.

[John A. Brooks:]

The shortfalls primarily all on the non op and but going into ’14, we are drilling, as we go into pad drilling, what really drives that lumpiness, as we are drilling more wells per pad. So, if you are doing a two in a three well pad, you have a certain cycle time associated with that and you got to four well pads and higher, that cycle time, it gets extended little bit and that lets in itself to this a little more choppiness?

[Steve Berman:]

Got it. Question for Steve, of course. You had two straight quarters of LOE per BOE beginning with a afforded the guidance for Q4 is kind come back into the mid fives. Is that just being conservative, is there something specific and might make it go up and then also any quest guidance, that you can give us for 2014, at least directionally on some of the main components?

[Steven A. Hartman:]

Okay. For LOE it might be on a little bit on the high side but we already lowered our guidance $0.63 I think, for the fourth quarter we have done was pretty aggressive. Fourth quarter tends to be a higher cost because we have more paraffin expenses and such. And also we just have more Eagle Ford oil coming online and that's just as a way it average goes a little bit higher LOE then some of the gas. So, all that said, I think that it is probably going to creep back up into the fives, but we were pleasantly surprised with the third quarter, so I am all for that, we are going to be on the lower end of that range.

[Steve Berman:]

2014 just, any color you can give us?

[Steven A. Hartman:]

2014 is probably good to be in the fives. You know, I would expect that there is a increases that we are guiding toward to start to level off, so probably the mid fives.

[Steve Berman:]

All right. Thank you very much.

[Baird Whitehead:]

Thanks Steve.

[Operator:]

Thank you and our next question comes from David Tameron from Wells Fargo. Please go ahead.

[David Tameron:]

Hi, morning. Couple of questions. If you think about the – if I want to decide to get rid of that acreage, do you guys have a point on that?

[Baird Whitehead:]

We do not.

[David Tameron:]

You do not, okay. Okay. Asset sales and I know you talked about someone to the past, but can you just remind us where you are at, outside the pipeline, what number should we be thinking about as far as, within the portfolio today, what could be sold as far as a dollar amount?

[Baird Whitehead:]

Well, I prefer not to give you a dollar amount. Every time we do that, it seems like those numbers tend to get out there and tend to have some bearing on the overall prices we get back. But you know, the gap, the remaining assets we have are Mississippi or [indiscernible] we have East Texas and we’ve the Granite Wash. There is casing made we would consider our selling both to Granite Wash and [indiscernible] in all likelihood we would not sell East Texas just because it's a – it's a large asset, has a lot of running room, if gas prices ever got back up to the point, it may sense to try to do something it has a shale potential, so that's an asset we will in all equities hold on but we would consider selling either the chalk or the Granite Wash or both.

[David Tameron:]

Okay. Yes. I understand the hesitancy in giving the number. And you might have missed this, but on the cost side, can you talk about which are current well cost are?

[John A. Brooks:]

Yes. I think we are planning on averaging about $8 million a well.

[David Tameron:]

Okay. And obviously the cost, you had some good, some pretty cost reductions, how should we think about that, I mean, you say that, the average, is that a 2014 number, how should we think about that? How much more can you squeeze out of that going forward?

[John A. Brooks:]

Well, they’re additional savings to be add on pad drilling side and continuing to optimize drilling and completion, but at this point we are planning on $8 million average well cost and do I think we can beat that, yes, but I am hesitant to put a number out there yet, and until we have some repeatability on it. We beat that number already, but we need to make sure we can repeat it.

[David Tameron:]

Okay. All right and final question, it's more of a housekeeping model question. Your DDNA rate – you might assume that the impairment charge that you took in the third quarter, is that already built into fourth quarter DDNA rates?

[Baird Whitehead:]

Yes, it is David

[David Tameron:]

It is, okay. That's all I got, thanks for the follow-up.

[Operator:]

Thank you and our next question comes from Amir Arif from Stifel, please go ahead.

[Amir Arif:]

Thanks, good morning guys. Just a couple of quick questions. First just on the Eagle Ford test that you are going to be doing, did I catch that, right in terms of they are going to start growing in December so would we have results with a one-two results or which you be putting something out other than that?

[Baird Whitehead:]

Amir, I think in all likelihood it probably would be in the second quarter. By the time you get to two wells drill, we are going to complete it and get them. Fall back for a period of time to understand we have, to understand a communication is because that's the primary reason why we are doing this test, try to see if they are, two separate reservoirs. So, I’d say it's more of a second quarter event.

[Amir Arif:]

Okay and then in terms of the full year guidance on the oil side, can just give us the parameters of what would cost it to at the 40% range versus the 70% range?

[Baird Whitehead:]

That was just the math of the 9 million to 10 million BOE range over the midpoint of 2013. So I think it will just be your standard one year out variability in results, working interest things like that.

[John A. Brooks:]

I mean within the plan we have I think 90 gross, 52 net wells, if memory serves me correct. So, you know, there is, you continue move things around, working interest wise, that it has some tweaking but it really just a range this time and just to give us some room that we can – that we can work within.

[Amir Arif:]

Okay. And then on the realized pricing on Eagle Ford, can you just give us a sense of how the–they seem to have come down. Are they stabilized at these levels or it just gives that less along with WTI now? That is expecting sort to state concept from these levels.

[John A. Brooks:]

We are assuming $90 WTI and $5 basis differential to LOS, so $95 LOS and then we are keeping with what we seen for transportation costs from Eagle Ford to LOS market of $7, so we are assuming $2 off WTI.

[Amir Arif:]

Okay. And the additional acreage that you are adding, is that all just tack on acreages within the same area that you focused on or you looking at other areas to get to the 100,000?

[Baird Whitehead:]

No, this is our backyard Amir. Lot of it is adjacent to what we already have or all of its adjacent what we already have. Lot of it's in, outstanding our shot at acreage. I think we – in our analyst meeting in mid November, we will provide a lot more color on, where these 5,000 new acres are, we are not going to tell you exactly where the 7,000 new acres are, we are planning to picking up in the fourth quarter but you can see how this stuff will pick it up, is either in a month what already we have, filling some holes or is it adjacent what we already have. So it tells a good story.

[Amir Arif:]

Okay. And then just one final question, in terms of as your free cash flow expense starts to narrow and that as you’ve got more acreage and more inventory, potentially with the down space. I mean you are looking to potentially accelerate, maybe end of ’14 or heading into ’15 or you focusing a little more on planning up the balance sheet before acceleration?

[Baird Whitehead:]

We are focused on cleaning up balance sheet. I mean there's a case image, it can accelerate that actually accelerated growth in EBITDAX which is a lag, probably about a year and half. So, at this point in time we are focused on cleaning up the balance sheet, either as case we made at some point in time because of the acceleration of growth in EBITDAX or product price and cooperation more so than our assumptions. Then we may consider doing something at that time but I can tell you, we are focused on cleaning up the balance sheet.

[Amir Arif:]

Okay. But potentially what the hedges over the asset sales and what the down space, if there potential heading into late 14 or I just start looking into 15 maybe?

[Baird Whitehead:]

Yes. Probably more of’15 advantages, that is where we estimate. But as we kind of proceeds we did on what we are considering selling.

[Amir Arif:]

Okay. Sounds great. Thanks guys.

[Operator:]

Thank you and our next question comes from Neal Dingmann from SunTrust. Please go ahead.

[Neal Dingmann:]

Morning gang. Great guidance. Baird for you or John, just wondering, given I guess not a huge backlog but given the backlog, as well as you do have, and then adding the new rig, how do you see, you’ve given color for ’14 as far as production guidance. How do you sort of, I guess it is safe to say you get a bit of a pop in the first quarter and then kind of a gradual after that?

[Baird Whitehead:]

That’s pretty your assumption, which you know just because of what we are saying ’14 the addition of the rig that we picked up, we are not seeing very low benefit of ’14 and so by definition most of that pump you will see in early ’14, that’s correct.

[Neal Dingmann:]

Okay and then looking you know just at the new acreage now that have picked up that is obviously block some more acreage in are you can able to now because of this you’ve already been doing this better as far as the lateral links not just obviously the pad drill and in space that John was refereeing to, but wondering on lateral link, how we can think about that going forward pretty much had a set rate of is this going to allow you opportunities maybe even try to expand that?

[Baird Whitehead:]

John why don’t you take that question.

[John A. Brooks:]

Sure, I mean we’ve demonstrated a few times that we can drill really long laterals 9,000 foot or better. There becomes a mechanical challenge in a point diminishing returns on some of those really long laterals where they are in the deeper part of the play, so right now I think we are trying to keep them under 8,300 foot type of lateral, we don’t necessarily need a 9,000 foot lateral, we know we can do we proved it, but would probably better off in the 8,000 foot or less.

[Neal Dingmann:]

That’s prefect guys, thanks and keep up the good work.

[Baird Whitehead:]

All right, thanks Neal.

[Operator:]

Thank you, our next comes from Scott Hanold from RBC Capital Markets. Please go ahead.

[Scott Hanold:]

Thanks good morning. Good quarter guys. I am to drill down a little bit more on a your non op partner in, you are stepping back, I mean what is your net acreage exposure to your operated activity and I guess the question I would ask is you know why not, why not non consent on those wells and just the pickup that six drilling and focus on your core assets which have generally been getting better performance?

[Baird Whitehead:]

Well, to answer your first question, it’s about 6,500 net acres. To answer your second question we have gone on like you said, we will selectively in all likelihood [indiscernible] on some future wells depending on where they are and those kind of things and lateral links and that kind of stuff. The case we made we would pick up a six rig because we've not consented or maybe they lay down even that last rig. We will do whatever we have to operationally to make up any difference because of non consent or they just decide to quit drilling. We have to be careful for what we now consent because we non consent something you’re out of your working issues are reduced to subsequent wells and we have to be cognitive of what the overall effect is by going non consent. But there is a case we may, we will select we get going non consent or some things in 2014.

[Scott Hanold:]

And when you look at some of that the more recent wells they have been drilling, would you say that they have met your economic threshold or where we are at with that I mean, could that decision be made on just, they are not hitting that threshold so it’s a better economic decision to lose the acres all together even at this point?

[Baird Whitehead:]

Well, they are economical let me put that concern to rest they are economical they just go about it in a different way as for us solid flow the well is back. They are very conservative on flow back and it’s on it is very -- is not an unusual to see their production increase over a longer period of time. We tend to get oil almost immediately up in, in a neck of the woods and which they are drilling wells and which we have acres it does act differently your RP rates are not quite as high even when you do flowing back more aggressively. But they get back on curve, they just get back on the curve further down the road so it does because of the lesser upfront production it does have an effect on economics, but it doesn’t kill them.

[Scott Hanold:]

Okay, so basically what I am hearing is the rocks are still really good here so you certainly would like keep that acreage if possible?

[Baird Whitehead:]

That’s exactly right.

[Scott Hanold:]

Okay that’s fair enough and on the down spacing test, what level of interference have you seen to this point on some of the closer space you’re done. I mean, do you still I mean feel pretty strongly on that you know that tighter spacing you know should be pretty good are you start to feel a little bit of communication I know some is good but I mean what level are we at right now?

[Baird Whitehead:]

John why don’t you take that question please.

[John A. Brooks:]

Well, all of them multi-well pads where we drilled tightly spaced wells, we have seen IP rates just up the roof so. The tightly spaced well in new unites you cannot draw any conclusion other than that it is working and working spectacularly. The real question that one wonders is how does it affect say in older well that’s nearby. And we haven’t, we don’t have a big dataset on which to draw what we have seen is some positive interference and some negative interference meaning, we had, we had some wells have relative increased in production due to nearby fracking and some that had diminished amount of production. The case that comes to mind for me as we had an older well that we obviously we shut in what we’re doing in offset frac. And when we turned everything back on and we went in and cleaned out that put the well and it got back to 90% of its production. So you can live with that diminishment, I think that fits in the overall story of drilling more wells and given rock volume it might reduce one wells per well rate of return somewhat but it doubles the volume of oil recovery, it doubles your PV for the 640 acres volume of rock that we model. On the other hand we had some two instances where in the south-western part of our acreage where it’s proximal to the hunt operated. Wells, where we -- where the rock is naturally fractured, so it’s a little bit more challenging to drilling complete. We had a three well program down there and they were not necessarily pad wells, but for holing the second well another well that we are already IP that 400 to 500 had this production rate increased to 1,400 barrel today and in the second instance where we reactivated than old Austin chalk well that would previously been stripper well to up -- highly profitable well put it that way so. You have both on – and just to summarize all that the tightly spaced wells are new well pads, works like a charm on the -- on the pad wells that are offsetting older wells, you have some diminishment, some increase in small dataset from which to drawing conclusion at this point.

[Scott Hanold:]

Okay fair enough that was to very helpful thanks.

[Operator:]

Thank you and due to time we ask the next questioners to please ask one question and to please queue again for a follow-up. Thank you. Our next question comes from Chad Mabry from MLV & Company. Please go ahead.

[Chad Mabry:]

Thanks, good morning.

[Baird Whitehead:]

Hi Chad.

[Chad Mabry:]

I just wanted to drill down a bit on 2014 CapEx if I heard you right for planning about 90 52 net wells in Eagle Ford that get you little over 400 million. Just kind of curious what you’re budgeting there for leasehold and then for mid stream and other AMP next year?

[Steven A. Hartman:]

Okay Chad, this is Steve we are assuming about 3% of our capital program will be for land it’s about $15 million spent on the expanding the Eagle Ford, we have about 2% of our capitals for facilities that’s for the water, system that John had described in a little bit of well high end. We did assume that the most of the CapEx will be picked up the midstream provider. And in the balance other than drilling and completion will be for seismic and other specifically are still program.

[Chad Mabry:]

All right, I appreciate it, thank you.

[Operator:]

Thank you and our next question comes from Biju Perincheril from Jefferies. Please go ahead.

[Baird Whitehead:]

Hi, Biju.

[Biju Perincheril:]

Hi, good morning. I had a quick question on the midstream sale can you talk about the impact to realization and operating cost when that’s completed?

[Baird Whitehead:]

Steve do you want to take that?

[Steven A. Hartman:]

Sure. Hi Biju, that I think that we would have about $1 million of extra costs some of it classified as LOE, some of it classified as gathering and processing in the first year and it probably expands about $2 million a year and the out years, we are looking at rates of about $0.26 for gathering and $0.30 for compression.

[Biju Perincheril:]

Any impact your realizations?

[Steven A. Hartman:]

The realizations -- nothing for realizations just the extra, just the extra cost.

[Baird Whitehead:]

LOE issue.

[Steven A. Hartman:]

Yes that’s not the oil issue, that just gas.

[Baird Whitehead:]

Just gas.

[Steven A. Hartman:]

So that’s just taking us into the gathering and energy transfer and over the range plan.

[Biju Perincheril:]

Got it, thanks.

[Baird Whitehead:]

If we get just to interrupt. If we get your pipeline part on market we sold, there would be a transportation component by doing that but in all likelihood that’s going to make it because your transportation rate moving through the pipeline in total would be less than what our trucking expense would be, so it may be a slight uptick in price realization. Depending on what kind of base we get back once we get to a pipeline stuff sold.

[Biju Perincheril:]

I got. And then you’re also selling the right for laying an oil pipeline, oil gallon line in the same day, right?

[Baird Whitehead:]

Well yes we are just talking about it will be in same -- some it may be in same right away it would not be in a same ditch per say, but a lot of may be in same right away is the -- our gas, gas gathering, gas lit systems.

[Biju Perincheril:]

And then, is there a commitment from the buyer to lay that pipeline?

[Baird Whitehead:]

Yes because there is no oil pipeline in the ground at this time, so really what we’re selling, we are selling right for somebody to come in and lay that old gathering system.

[Biju Perincheril:]

Right. I was asking if the potential buyer in the bids that you seem so far or you’re structuring the deal such that the buyer will then come and lay that oil pipeline or --?

[Baird Whitehead:]

There is some confusion here, what we are selling is the gas gathering, gas lit system that is a separate package. The oil pipeline part would be a separate package will put up for a bid so that may and it probably is going to be two different buyers.

[Biju Perincheril:]

Got it, thanks.

[Baird Whitehead:]

Okay.

[Operator:]

Thank you and our next question comes from (indiscernible) from Global Hunter Securities please go ahead.

[Unidentified Analyst:]

Good morning. Just a modeling question last two quarters you’re able to use the working capital to get back about $50 million and trying to figure out to get your credit facilities that the end of the year you’re expecting you have to give back and that 50 million?

[Steven A. Hartman:]

Working capital plucks as always a tough first part of coming up with these forward-looking financial models I think when we are looking at is probably having to give up a little bit back, but I think that we got all, we got all those working capital assumption baked in when I give you the where we expect a credit facilities the end of the year 185 to 195 I think what I stated so that all the working capital adjustments would be included in that.

[Unidentified Analyst:]

Thanks Steve.

[Operator:]

Thank you and our next question comes from Adam Leight from RBC Capital Markets

[Baird Whitehead:]

Hi Adam.

[Adam Leight:]

Fortunately most of my questions were answered and maybe this one sort of follows on scratch question but I’m not sure, but there was seem to be there was a lot of variance in well result particularly in the Hunter wells. Can you provide a little bit color on what might have caused that is that locational is it?

[Baird Whitehead:]

John, I’m not sure exactly what I was talking --

[John A. Brooks:]

Yes I think so you referring say like to Gonzale and say the Platypus Hunter are the difference there.

[Adam Leight:]

Yes.

[John A. Brooks:]

Yes Gonzale wells where are shorter laterals and as you do go north and that is the northern tier of the acreage you get little shallow when you have little bit GOR. So the wells are cheaper to drill and though have a slightly lower of IP rates, so not a really big shocker force is especially given they were shorter laterals.

[Adam Leight:]

To the rate per stage was also low is that.

[John A. Brooks:]

Yes that will be the function of just a lower GOR and less gas as for energy.

[Adam Leight:]

Okay, great, thanks.

[Baird Whitehead:]

It kind of wells there intend to have a shallower decline upfront and what we see is we go down that in a deeper part of our acreage so that there is a tipper -- there is a different side curve whereas net, net we still think the reserves are pretty similar they just have a different production profile associated with it.

[Adam Leight:]

Okay that’s great thank you.

[Baird Whitehead:]

You are welcome.

[Operator:]

Thank you and I’m not showing any further questions at this time, I would now like to turn the call back to Baird Whitehead for any further remarks.

[Baird Whitehead:]

All right, thanks Danielle. Thanks for listening in our call. I mean, I hope that everybody can see that we are making lot of progress in this company. We’ve made a tremendous amount of progress here this year, we expect to make a lot of progress in 2014, we’ve got a great position and a growing position and where we consider very economical play this time, but as important is our production reserve growth in a short term. I’ll continue to say again, we are focused on our balance sheet and we are focused on reducing our spend over the next two to three years as we grow the EBITDAX as we get some nonstrategic assets on the market, so. In any case thank you very much.

[Operator:]

Ladies and gentlemen, thank you for participating in today’s conference. This does conclude today’s program you may all disconnect. Everyone have a great day.