Ranger Oil Corp (ROCC) 2013 Q3 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Penn Virginia Corporation's third quarter 2013 conference call. At this time all participants are in a listen-only mode. Later we 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 like to introduce your host for today's conference, President and CEO, Baird Whitehead. Please go ahead, sir.

Thank you, Danielle. I would like to welcome you to Penn Virginia's third quarter 2013 conference call. I'm joined today by members of our team, including John Brooks, our Executive V.P. 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 statements 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 of production at Eagle Ford as well as lower unit operating costs.

Some of the financial highlights for the third quarter include product revenues of $122 million, or about $67.00 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 by itself was 83% of our third quarter product revenues. Operating margin of approximately $51.00 per barrel equivalent, an increase of 10% over the second quarter. Operating income which excludes $132 million of impairment expense of approximately $24 million and 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 made progress in every category I just went through. While our production in revenues did increase in the third quarter the increase was less than we had expected due almost solely to lower than expected production from our non operated Eagle Ford Shale activity. This was caused by drilling issues which, in turn, caused delays in completions. The outside operator subsequently dropped the rig which caused further variances in the third quarter in production.

As a result we reacted as quickly as we could and increased the operating drilling rig count by essentially one. It is now expected we will utilize a five rig drilling program during 2014 and we have assumed a one rig outside operator program. Clearly, the increase in operated activities 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, a more substantial benefit will occur during the first quarter 2014.

With the total 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 percent for the fourth quarter 2013 to the fourth quarter of 2014. In addition we recently completed our mid year reserve evaluation. The [prude] reserves in the Eagle Ford almost doubles from 26 million barrels equivalent at year end 2012 to about 51 million barrels mid year this year. The prude developed portion of the Eagle Ford alone increased from 9.7 million barrels at year end 2012 to 19.8 million barrels at mid year. And, which really is the scorecard, our Eagle Ford Shale 3P reserves, which includes the probable and possible on top of the prude are now about 170 million barrels.

If you remember pro forma Magnum Hunter we had estimated about 140 million barrels. So within a very short period of time we have been able to increase the 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 [dye] space and add acreage. We now have approximately 107,000 gross acres, 67,000 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 $1,600.00 an acre. And as new acres opportunities continue to develop we recently decided to go ahead and add another $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 received a question by Neal Dingmann in last quarter call, ultimately, where we wanted to be acreage wise and I said at that time about 100,000 net acres. But 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 at the $1,600.00 per acre clip. As of 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 ten years with a six rig 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, the 3P reserves increase the value of the company increases so it is pretty clear why we are pretty excited about what we are doing in Eagle Ford right now with this low cost acreage addition. Not only are we increasing reserves but, just as important, the value of those reserves is increasing as we continue to lower well costs 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 mid year reserve report the borrowing base under our revolving credit facility was recently increased from $350 million to $425 million.

As a result the financial liquidity, as of September 30, was approximately $330 million as compared to about $300 million as of June 30th. 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 divesting of some non core assets as we have said. The sale of these assets would help supplement and fund the [I] spend over the next few years. We did put our pipeline up for bid that we had announced. We are -- that is the Eagle Ford gas gathering and gas lift systems.

There was a tremendous amount of interest in both of these systems. We have received the bids which are currently being evaluated but, 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 high bidder and still expect to have that transaction closed by the end of this year or early in 2014. In addition, we will consider the sale of some of our gas year assets during the first half of 2014. We will also tentatively sell the rights to construct a [no] gathering system in the 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 at 2.5 times -- to 2.5 times going into 2016. So with that I would like to turn it over to Steve so he can provide an update of our financial progress.

Okay. Thanks, Baird and good morning. I will start with the financial review and as we do in the earnings release I will be comparing our third quarter results to the second quarter. Product revenues for the quarter were $121.6 million, or $67.33 per boe, up 11% over the second quarter. The increase driven by a 7% increase in product pricing and a 3% increase in production. Revenue from oil sales topped $100 million this quarter for the first time ever and that is 16% higher oil revenue than last quarter. Operating expenses $29.7 million for the quarter, or $16.47 per boe, which was $600,000.00 higher than the second quarter, adjusted for acquisition costs, but 1% lower on a per barrel basis.

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 costs across the board with the exception of some higher down hole repair costs. Gathering, processing and transportation expense was relatively flat at $1.68 per boe. Production and (inaudible) tax was lower than the previous quarter due to receiving some severance tax refunds this quarter related to prior year activity. G and A expense excluding, non cash share based and liability based incentive compensation was $10.6 million or $5.85 per boe, up $400,000.00 from the second quarter due some to one-time employee related expense items. And without those one-time costs recurring G and A would have been about $300,000.00 less this quarter than the second quarter. Operating margin, as described in our earnings release, increased by $4.77 per boe or 10% over last quarter to $50.86 per boe.

This increase was driven, as it has been for the last several quarters, by our very strong operating margin in the Eagle Ford, which was about $75.00 per barrel in the third quarter, excluding allocated G and A. Adjusted EBITDAX and non-GAAP pressure 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 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 Selma Chalk by about $1 million. Our DD and A expense decreased to $34.57 per boe, down from $36.80. And our exploration expense was lower 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 and other customary adjustments reconciled on page 10 of the release, our adjusted net loss attributable to common shareholders was $1.5 million or $0.02 per share. This is a $0.15 per share improvement over last quarter. We are pleased to be 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 costs, which John will discuss in more detail shortly. We also had lower spending on seismic and facilities construction. 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 letters of credit. On Monday earlier this week, as Baird already mentioned, we closed on our new credit facility borrowing base of $425 million, which is $75 million increase over our (inaudible) determination and $25 million higher than we had been guiding to in our last call. Pro forma for the borrowing base increase, our liquidity at the quarter end was $332 million.

Our leverage at quarter end was 3.6 times total debt to pro forma adjusted EBITDAX compared to our credit facility covenant of 4.5 times. Pro forma adjusted EBITDAX, which includes a $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 $90.00 WTI price and keep as much upside where we can. We currently have 9400 barrels per day of oil hedged for the remainder of 2013, which is 79% of the mid point of guidance at a weighted average floor of $94.69 per barrel. We have 8500 barrels per day hedged for 2014 which is roughly half of the mid point of our oil production guidance with the weighted average floor of $93.49 per barrel.

We started layering the 2015 hedges this quarter and have 2,500 barrels per day hedged for the year at a weighted average floor of $91.74. Our current hedge position is summarized on page 12 of the release. 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 short fall 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 the volume loss and adding land dollars for our lease acquisition program. Production is expected to be 1.8 million barrels of oil to 2 million barrels of oil equivalent for the fourth quarter, which equates to 19,200 boe to 22,200 boe per day.

For full year 2013, this would be a 6.8 million boe to 7 million boe, 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 effects 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 only 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 remained relatively stable since the effective lower volume was mostly offset by stronger product pricing in the third quarter. We lowered our mid point 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 and A was revised slightly lower to a mid point run rate of $9.9 million for the fourth quarter. Unproved property amortization, which is the primary component of exploration expense, was revised down ward to reflect a change in accounting treatment for how me amortized unproved property in Eagle Ford. Essentially, going forward, we are just going to move land costs over to wells as they are drilled and we won't amortize land cost exploration expense. DD and A was also revised lower on a unit basis because of higher than anticipated proved reserve adds in the mid year reserve. For adjusted EBITDAX we are moving the mid point for full year 2013 lower by $4 million to account for the effects of lower production in the higher one time employee related costs in the third quarter I already mentioned.

We now expect full year adjusted EBITDAX of $321 million to $332 million. This implies a range of $89 million to $100 million for the fourth quarter. At the mid point this would be a 7% increase over the third quarter. Our capital expenditures guidance is now $500 million to $530 million, which implies fourth quarter CapEx of $139 million to $169 million. This adds $20 million to 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 to 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 3.5 times with pro forma adjusted EBITDAX for leverage calculation purposes being $26 million higher than our guidance. This year end 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 pickup in liquidity, since we don't lose any borrowing based value with the sale of that asset, and a year end leverage ratio of around 3.3 times.

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 will provide our full 2014 guidance in February, as we usually do. As Baird mentioned we expect to run a five rig operated program through 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 for total production volume is 9 million boe to 10 million boe or 24,600 boe to 27,400 boe per day. This would be a 30% to 45% increase over the mid point of 2013 guidance. Crude oil production is expected to increase 65% to 85% over the mid point of 2013 guidance and that implies 2014 oil production of 5.8 million barrels of oil to 6.5 million barrels of oil equivalent. Our growth in year end oil production exit rates, which we are defining as fourth quarter 2014 oil production over fourth quarter 2013 oil production, is expected to be 40% to 70% growth. And we expect this program to be fully funded with the liquidity we have on hand going into 2014.

We expect to fund the program with cash flow from operations from the Eagle Ford gas gathering systems, proceeds from some non cap, non core asset sales and increases to our borrowing base. Although it is difficult at this point to estimate what our borrowing base increases will be and what asset sale proceeds will be, we feel comfortable saying that we expect to maintain at least $200 million of liquidity through 2014. And we expect our leverage at the end of the year will be around 3.0 times even without any non core asset sales beyond the gas gathering system. So with that, I would like to pass it off to John for our ops update.

Thanks, Steve, and good morning. As Baird mentioned in the third quarter our production and asset bases increased and we continued 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, a 9% sequential increase. We had record quarterly oil production of 10,373 barrels of oil per day, a 10% sequential insurance -- increase. Oil and NGL volumes 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 some what 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 158 Eagle Ford Sale producing wells. We have ten 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 and 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 length for these 18 wells was approximately 5,900 feet with an average of just over 24 frac stages. In general the high rates can be attributed to longer lateral lengths and, therefore, more frac stages. But also we believe we are beginning to see the advantages associated with pad drilling and closer well spacing, which improves induced frac [efficiencies] and, therefore, overall production rates.

Sixteen of our recently drilled wells were drilled off of six multi well pads or roughly three wells per pad on average. Effective nominal spacing on these six pads averaged 73 acres. The closer spacing and use of zipper fracs appears to be working well. In addition we used an average 1,168 pounds of profit per foot of lateral since mid year 2013. This compares to an average of approximately 915 pounds of profit per foot for the wells completed previously. We believe that increasing this frac intensity improves our productivity per stage with a nominal increase in cost. Going forward, since much of our legacy acreage is now held by production, we will continue our development program focusing more on pad drilling and tighter spacing. Our average total well cost on a per frac stage basis, including drilling and completion costs was approximately $350,000.00 in the third quarter of 2013 compared to approximately $430,000..00 in the second quarter of 2013, which is a 19% reduction in costs.

The average stimulation cost per frac stage was approximately $110,000.00 in the third quarter of 2013 compared to approximately $150,000.00 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 of our stimulation design. Now this includes going to a hybrid frac design which minimizes gel requirements as well as reduced potential formation damage, increasing our sand concentrations up to 4 pound per gallon, where the formation will take it, and on a quicker ramp which reduces water, chemical and pump times. Using 100 mesh on the front end to improve overall fracture complexity and replacing the more expensive [ceramic profit] with a resin coat on the tail end, which not only reduces the cost but also reduces or eliminates profit flow back while providing the advantage of higher closure stress.

Our stimulation design continues to evolve as we more tightly engineer our fluids and pumping schedule to further increase the amount of profit pumped per foot of lateral while keeping incremental costs low and when we do that on a multi well pad the completion efficiencies just multiply. On the drilling side, additional efficiency gains are realized from pad drilling, and whenever possible, we're using smaller spudder rigs to preset surface casing on multi well 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 to rig release portion of the overall cycle time by about two days per well and saves about $75,000.00 per well.

Using the drilling pad is also complemented by use of the rotary steerable directional tools which we've been using, which deliver a better well bores and increased rate of penetration further saving over $200,000.00 a well. And all of that all adds up to three straight quarters of declining well costs with longer laterals and more frac stages. In the third quarter we drilled and completed 16 wells with average total well costs right below $8 million. We recently added an operated rig in the attempt to mitigate the fact that our partners in our non operated acreage released a rig in the third quarter. And, as we've already mentioned, this step will have little production benefit in the fourth quarter of 2013 with most of the benefit being realized in first quarter of 2014. During the fourth quarter of 2013 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, the fourth quarter 2013 production is expected to be approximately 19,300 boe to 22,300 boe per day. Over next few years we expect to continue to drill approximately 90 gross Eagle Ford wells per year assuming an ongoing six rig program, five of which would be operated rigs. If our non operator laid down the remaining rig, in all probability, we would add a sixth operated rig to offset the reduction in activity. Sequential quarterly production growth in 2014 beyond the first quarter could be lumpier due to an increased emphasis on pad drilling and the fact that the spud to sale 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 for us is 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 have 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 fresh water from surface impairments and significantly reduce volumes of freshwater from sub surface sources.

A business perspective we think it is 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 Penn Virginia's commitment to good stewardship of increasingly scarce water resources in the environment as a whole. The up front capital costs to achieve these goals are substantial but, over the ten year 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 pumped down a disposal well, we should be able to reclaim those water volumes for reuse at a cost that is competitive with merely disposing of them.

Well, actually, we remain enthusiastic for the potential of the upper Eagle Ford Shale Interval. In December we will spud a two well exploratory test of the upper Eagle Ford Interval in the southern portion of our Lavaca County acreage as a follow up to our successful [Fistic Number One Well] in the northeastern portion of our Lavaca County acreage. If this test 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 has potential to add significantly to our drilling inventory. So with that, I will turn it back to you, Baird.

All right. Thanks, John. Danielle, we are ready to go ahead and take any questions, please.

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

Good morning, guys, and congratulations.

Hey, Brian.

The inventory, the new inventory numbers you put out does that include the recently acquired 7,000 acres?

Well, the 7,000 acres we're currently securing that in this fourth quarter. But that does not include that 7,000 acres, no.

Okay. And then two other questions. One, you all talked about the 70 acre to 75 acre spacing is 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 acre to 75 acres?

Yeah. It just -- it just happened to work out that way this quarter, Brian. We are taking some wells, correct me if I'm wrong, John, but we are taking some wells down to about 400 feet or, I think, the actual number is like 375 feet between laterals here soon. That will probably be around 45 acres or so. So, yes, there are some wells that are bigger, some wells that are less than 73. But we continue to drive those lateral distances down.

Okay. That's helpful.

John, do you have any data -- do you have anything to add to that, John?

Yes. I would just say that the 73 acres was an average during the quarter. The bulk of those were 61 acre spacing. Most of them between 400 foot 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.

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

Brian, as far as over what part of our acreage, this thing exists. We have an (inaudible) based on the well control we have. We have vertical wells we drilled to get open hole information on the lower Eagle Ford in general. We think it is probably over half to two thirds of our acreage where we think it's prospective. It's highly calcareous as compared to lower Eagle Ford. As far as the reserves go, we only have the one data point at this time. Based on thickness of the upper Eagle Ford, based on porosities of the that upper Eagle Ford, based on the open hole information that we do have and the logging information we have, you could -- if they are separate you could, volumetrically, come up with a number that's pretty similar to what the lower Eagle Ford on a per well basis.

All right, guys. Thank you.

Thank you.

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

Good morning.

Hey, Welles.

On the upper, lower Eagle Ford tests is this new one, is it going to be stacked directly or is it going to be modestly offset implying kind of a Chevron design? I guess how far apart are they going to be, are those well bores going to be vertically and horizontally?

John.

Yes. They are not going be stacked vertically. They will be offset some what. We are still in the process of permitting the wells. I can't give you the exact footage but they'll probably on the order of maybe 500 feet or 600 feet apart in the plan view.

Okay. And then is the placement going to be any different, the placement or the completion going to be any different from you're initial Eagle Ford well, which, if I remember correctly, was completed pretty much the same as the lower?

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

Okay. Perfect. And then, just to cover all the bases, the drilling issues that your non op partner had -- is it fair to say those were mechanical in nature and had nothing to do with the rock?

Yes. I think that is a fair statement. The two wells, they're -- well, they're drilling one of two wells on a two well pad right now. And after they finish these two wells all of the jointly held acreage that we have with them will be [HBT'd]. So I think that may be driving their decision in some part. We are a little bit further up the learning curve than they are in this area. We've drilled well over 100 wells and they have drilled, maybe, 30. So there is a learning curve involved.

Okay. Perfect. That is all I have. Congrats.

All right. Thanks, Welles.

Thank you. Our next question from Steve Berman from Canaccord Genuity. Please go ahead.

Hi, Steve.

Good morning, everyone. Let me follow up on Welles' question. Any chance you could take over operatorship from [Hunt] as far as the [JV] goes? You're obviously doing a better job than they are.

That's a very difficult question to answer. I think, at this time, we continue to talk to them, continue to have ongoing operational meetings to try to share information back and forth to help them on the drilling completion side. But, at this point in time, I think it'd be premature for us to make any assumption that we could take over operation. That's always a difficult challenge.

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

The short fall's primarily all on the non op. But going into 2014 we are drilling. As we go into pad drilling what really drives that lumpiness is we're drilling more wells per pad. So if you're doing a two and three well pad you have a certain cycle time associated with that. And you go to a four well pads and higher that cycle time gets extended a little bit and that lends itself to just a little bit more choppiness.

Got it. Question for Steve on the cost side. You've had two straight quarters of LOE per boe beginning with the four. The guidance for Q4 is kind of back into the mid fives. Is that just being conservative? Is there something specific that might make it go up? And then -- and also any cost guidance or thoughts you can give us for 2014, at least directionally on some of the main components?

Okay. For LOE it might be a little bit on the high side but we already lowered our guidance $0.63, I think, for the fourth quarter so we thought that was pretty aggressive. The fourth quarter tends to be a higher cost because we have more parafin expenses and such and also we just have more Eagle Ford oil coming online and that is just, as a weighted average goes, a little bit higher LOE than (inaudible) some of the gas. So all that said, I think that it's probably going to creep back up into the fives but we were pleasantly surprised with the third quarter. So I -- I'm hopeful that we're going to be on the lower end of that range. And then in 2014--

And 2014? Any color you can give us?

2014 is probably going to be in the fives. Yes. I would expect that those increases that we were guiding towards would start to level off so probably the mid fives.

All right. Thank you very much.

Thanks, Steve.

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

Hi, good morning. A couple of questions.

Hi, David.

If you think about the -- if Hunt were to decide to get rid of the acreage, do you have a [pref] rate on that?

We do not.

You do not? Okay.

We do not.

Okay. Asset sales, and I know you've talked about some of this in the past, but can you just remind us where you're at? Outside of the pipeline what number should we be thinking about as far as what's in your portfolio today? What could be sold as far as a dollar amount?

Well, I would 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 the remaining assets we have are Mississippi, are Selma Chalk, we have east Texas and we have the Granite Wash. There is a case to be made that we would consider selling both the Granite Wash and the Chalk. In all likelihood we would not sell east Texas just because it is a large asset, has a lot of running room. If gas prices ever got back up to the point that it made sense to try to do something, it has Haynesville Shale potential. So that's an asset we will, in all likelihood, hold on. But we would consider selling either the Chalk or the Granite Wash or both.

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

John?

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

Okay. And, obviously, the costs -- you've had good, some pretty good cost reductions. How should we think about that? You say you are averaging -- is that a 2014 number? How should we think about that? How much more can you squeeze out of that going forward?

Well, there are additional savings to be had on the pad drilling side and continuing to optimize drilling and completion but, at this point, we are planning on $8 million average well cost. Do I think we can beat that? Yes. I'm hesitant to put a number out there yet until we have some repeatability on it. We beat in number already but we need to make sure we can repeat it.

Okay. All right. And then final question. This is more of a house keeping model question. Your DD and A rate is trending lower. Am I do assume that the impairment charge that you took in the third quarter, was that already built into fourth quarter DD and A rates?

Yes, it is, David.

It is. Okay. That is all I got. Thanks for the follow up.

All right. Thank you.

Thank you. Our next question comes from Amir Arif from Stifel. Please go ahead.

Thanks. Good morning, guys.

Hello, Amir.

A couple of quick questions. First on the Eagle Ford tests that you are going be doing, did I catch that right in terms of you are going to start drilling in December? So would we have results with 1 Q results or would you be putting out something sooner than that?

Amir, I think, in all likelihood, probably would be in the second quarter. By the time we get the two wells drilled, we get them completed and get them flowed back for a period of time to understand what we have, to understand the communication issue -- Because that is the primary reason why we are doing this test, to try to see if they are two separate reservoirs. I would say it would be more of a second quarter event.

Second quarter event? Okay. And then, in terms of the full year guidance on the oil side, can you give us the parameters of what would cause it to be at the 40% range versus the 70% range?

That was just the math of the 9 million boe to 10 million boe range over the mid point of 2013. So I think it would just your standard one year out, variability in results working interests, things like that.

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

Okay. And then on the realized pricing in the Eagle Ford can you just give the sense of how the -- the (inaudible), it seems to have come down. Are they stabilized at these levels or (inaudible) given that LLS is in line with the WTI now? Are you expecting this to stay constant from these levels?

We are assuming $90.00 WTI and a $5.00 basis differential to LLS. So $95.00 LLS. And then we're keeping with what we have seen for transportation costs from Eagle Ford to LLS market of $7.00. So we are assuming $2.00 off WTI.

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

No. This is in our backyard, Amir. A lot of it is adjacent to what we already have. All of it is adjacent to what we already have. A lot of it's in our offsetting our Shiner acre. I think we'll hit our analyst meeting in mid November. We'll 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 that we plan on picking up in the fourth quarter but you can see how the stuff we are picking up is either in and amongst what we already have, filling some holes or is adjacent to what we already have. So it tells a good story.

Okay. And then just one final question. In terms of as your free cash flow expense starts to narrow and as you have got more acreage and more inventory, potentially with the down space, are you looking to potentially accelerate maybe end of 2014 and heading into 2015? Or are you focusing a little more on cleaning up the balance sheet before acceleration?

It -- we are focused on cleaning up the balance sheet. There's a case you made, you can accelerate that actually accelerates your growth and EBITDAX but there is a lag--

Yes.

Probably about a year and a half. So, at this point in time, we are focused on cleaning up the balance sheet. There's a case to be made, at some point in time, because of the acceleration of growth in EBITDAX [or] product pricing 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.

Okay. So potentially with the hedges, with the asset sales and with the down spacings there is potential heading into late 2014 or as you start looking into 2015 maybe?

Yes. Probably more a 2015 event--

Yes.

Is what I would estimate. It depends on what kind of proceeds we get on what we are considering selling.

Okay. Sounds great. Thanks, guys.

All right. Thank you.

Thank you. Our next question from Neal Dingmann from SunTrust. Please go ahead.

Morning, gang. Great guidance. Baird, for you, or John, just wondering, given, I guess it's not a huge backlog, the backlog of wells you do have and then adding the new rig, how do you see -- You have given, I know, color for 2014 as far as production guidance. How do you -- I guess, is it safe to say you'll get a bit of a pop in the first quarter and then a gradual after that?

That is a pretty good assumption. We should just because of what we are seeing in 2014. The addition of the rig that we picked up, we're not seeing -- it's very little benefit of it in 2014. So, by definition, most of that bump you will see in early 2014, that's correct.

Okay. And then looking just at the new acreage now that you all have picked up -- have obviously blocked some more acreage in. Are you going to be able to now because of this? Or you've already been doing this, Baird, as far as the lateral lengths? Not just, obviously, the pad drill and the tighter space that John was referring to but wondering on lateral length. How we can think about that going forward? Are you pretty much at a set rate or is this going to allow you opportunities to maybe even try to expand that?

John, why don't you take that question?

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

Well, that's perfect, guys. Thanks. And keep up the good work.

All right. Thanks, Neal.

Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Thanks. Good morning. Good quarter, guys.

Hey, Scott.

Hey. I'm going to drill down a little bit more on your non op partner. And stepping back what is your net acreage exposure to their operated activity? I guess the question I would ask is why not non consent on those wells and just pick up that six drilling rig on your own and focus on your core assets, which certainly have been getting better performance?

Well, to answer you first question, it is about 6,500 net acres. To answer the second question, we have gone non consent. We will selectively, in all likelihood, go non consent on some future wells depending on where they are and those kind of things and lateral lengths and that kind of stuff. Is there a case to be made that we would pick up a sixth rig because we have not consented or maybe they laid down and evened that last rig? We will do whatever we have to, operationally, to make up any difference because of non consent or if they just decide to quit drilling. But we have to be careful of what we non consent because if you non consent something you are out of -- your working (inaudible) are reduced in subsequent wells and we have to be cognizant of what the overall effect is by going non consent. But if there is a case to be made we will selectively go non consent on some things in 2014.

And when you look at some of the more recent wells they have been drilling, would you say that they've met your economic threshold or --? Where are we at with that? Could that decision be made on just they are not hitting that threshold so it is a better economic decision to lose the acreage all together even, at this point?

They are economical. Let me put that concern to rest. They are economical. They just go about it a different way as far as how they flow their wells back. They are very conservative on the flow back and it is very -- it is not unusual to see their production increase over a longer period of time than what ours do. We tend to get oil almost immediately up in the neck of the woods in which they are drilling wells, in which we have offset acreage. It does act differently. Your IP rates are not quite as high even when you do flow them back more aggressively. But they get back on the curve. They just get back on the curve further down the road. So it does, because of the lesser up front production, have an effect on economics but it doesn't kill them.

Okay. So basically what I'm hearing is the rocks are still really good here so you certainly would like to keep that acreage if at all possible?

That is exactly right.

Okay. No, that's fair enough. On the down spacing tests, what level of interference or any have you seen to this point on some of the closer spacing you done? Do you still feel pretty strongly on that tighter spacing -- should be pretty good or are you starting to see a little bit of communication? I know some is good but what level are we at right now?

John, why don't you take that question, please.

Well, on all of the multiwell pads where we have drilled tightly spaced wells it's -- we have seen IP rates just out the roof. So the tightly spaced wells in new units, 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 an older well that is 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 have had some wells have relative increase in production due to nearby fracking and then some that have had a diminished amount of production. The case that comes to mind, for me, is we had an older well that we, obviously, shut in while we were doing an offset frac and when we turned everything back on we went in and cleaned out with that 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 in a given rock volume and might reduce one well's per well rate of return somewhat. But it doubles the volume of oil recovery and it doubles your [PB] for the 640 acre volume of rock that we model. On the other hand, we have had some -- two instances where, in the southwestern part of our acreage, it's approximal to the Hunt operated wells where the rock is naturally fractured. So it is a little bit more challenging to drill and complete.

We had a three well program down there and they were not necessarily pad wells but following the second well another well -- another well that we had already IPed at 400 or 500 had its production rate increase to 1400 barrels a day. And then the second instance where we reactivated an old Austin Chalk well that had previously been a stripper well to a highly profitable well, put it that way. So you have both. To summarize all that, the tightly spaced wells on new well pads works like a charm. On the pad wells that are offsetting older wells, you have some diminishment, some increase and it is just a small dataset from which to draw any conclusions at this point.

Okay. Fair enough. That was very helpful. Thanks.

Thank you.

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

Thanks. Good morning.

Hi, Chad.

I just want to drill down a bit on 2014 CapEx. If I heard you right, if we're planning about 90 52 net wells in the Eagle Ford, that gets you a little over $400 million. Just kind of curious what you are budgeting there for lease hold and then for mid stream and other A and P next year.

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 expanding the Eagle Ford. We have about 2% of our capital is for facilities. That's for the water system that John had described and a little bit of well tie in. We did assume that most of the CapEx will be picked up by the mid stream provider and then the balance, other than drilling and completion, will be for seismic and other, specifically our stealth program.

All right. I appreciate it. Thank you.

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

Hi, Biju.

Hi. Good morning. A quick question on the mid stream sale. Can you talk about the impact to your realizations and operating costs when that is completed?

Steve, do you want to take that?

Sure. Hi, Biju. 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 in the out years. We are looking at rates of about $0.26 for gathering and $0.30 for compression.

Okay. And any [tied to] realizations?

The realizations?

No.

Nothing for realizations.

No.

Just the extra -- just the extra costs.

Just the gas (inaudible) [LOE] issue. Yes.

Yes. Yes, that's not the oil, Biju. That's just the gas.

That's just gas.

So that is just taking us into the -- into the gather, into energy transfer and over to the La Grange plant.

Got it. Thanks. If I could ask--

If we could just interrupt. If we get the oil pipeline part on the market and sold there would be a transportation component by doing that. But, in all likelihood, that's going to make us money because the oil 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 what kind of bids we get back once we get the oil pipeline stuff sold.

Got it. And then you're also selling the right for laying an oil pipeline, oil gathering line to the same [ditch] as well, right?

Well, yes. What I was just talking about. It won't be -- it'll be in the same -- some of it may be in the same right-of-way. It would not be in the same ditch, per se. But a lot of it may be the same right-of-way as our gas gathering, gas load systems.

Got it. Is there a commitment from the buyer to lay that pipeline?

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

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

No. There is some confusion here. What we are selling is the gas gathering and gas lift system. That is a separate package. The oil pipeline part would be a separate package that we will put out for bid. So, in all probability, it's going to be two different buyers.

Got it. Thanks.

Okay.

Thank you. Our next question comes from Lou Nardi from Global Hunter Securities. Please go ahead.

Good morning. Just a modeling question. The last two quarters you were able to use working capital to get back about $50 million. I'm trying to figure out to get to your credit facilities at the end of the year, are you expecting to have to give back any of that $50 million?

Well, Lou, working capital plugs is always the toughest part of coming up with these forward-looking financial models. I think what we are looking at is probably having to give up a little bit back. But I think that we have got all of those working capital assumptions baked in when I give you where we expect the credit facilities to (inaudible) at the end of the year. The [185] to [195], I think, is what I stated. So that -- all of the working capital adjustments would be included in that.

Thanks, Steve.

Thank you. Our next question comes from Adam Leight from RBC.

Good morning, guys.

Hi, Adam.

Fortunately, most of my questions were answered and maybe this one follows on Scott's question, I'm not sure. But there was -- it seems to be a lot of variance in well result, particularly in the Hunter wells. Can you provide a little bit of color on what might have caused that?Is that locational? Is it --?

John, I'm not sure exactly what Adam is talking about. Do you know what he is talking about?

Yes. I think so. Are you referring, say, to the [Paganzo] and, say, the Platypus and Hunter -- the difference there?

Yes.

The Paganzo wells are shorter laterals. And as you do go north, and that is in the northern tier of the acreage, you get a little shallower and you have a little bit of [GOR]. So the wells are cheaper to drill and they will have a slightly lower IP rate. Not a real big shocker for us, especially given they were shorter laterals.

The rate per stage was also low, is it?

Yes. Now, that'll be the function of just the lower GOR and less gas and reservoir energy.

Okay. Thanks.

But those same kind of wells, Adam, tend to have a shallower decline up front than what we see as we go down dip in the deeper part of our acreage. There is a different type curve where as net-net we still think the reserves are pretty similar. They just have a different production profile associated with it.

Okay. That's great. Thank you.

You're welcome.

Thank you. 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.

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

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.