Penn Virginia Corporation (PVA) Q4 2012 Earnings Call February 21, 2013 10:00 AM ET
Baird Whitehead - President & CEO
Steve Hartman - SVP & CFO
John Brooks - SVP & Regional Manager, Gulf Coast Division
Neal Dingmann - SunTrust
Brian Corales - Howard Weil
Ray Deacon - Brean Capital
Welles Fitzpatrick - Johnson Rice
Steve Berman - Canaccord Genuity
Good day everyone and welcome to the Penn Virginia Corporation Fourth Quarter 2012 Earnings Conference Call. Today’s call is being recorded. At this time, I would like to turn the conference over to Mr. Baird Whitehead. Please go ahead sir.
Thank you, April. Good morning and welcome to Penn Virginia’s fourth quarter 2012 conference call. I am joined today by various members of our team, including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; John Brooks, our Executive VP of Operations 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 issued last night, as well as our Form 10-K, which will be filed early next week will apply to our comments this morning.
We would like to begin our discussion by expanding on the earnings release that was issued after the close yesterday.
The fourth quarter of 2012 continued a trend of solid financial results, achieving our sixth consecutive quarter EBITDAX of $60 million or greater with year-over-year increases in oil and natural gas liquid revenues and gross operating margins. We continue to drill excellent Eagle Ford wells in both Gonzales and Lavaca Counties and at this time we have almost completely derisked our entire Lavaca County acreage position. Our fourth quarter benefited from the addition of a third drilling rig late in the third quarter and we enter 2013 with operational momentum.
Our short -term goal is earning all the knocking sand acres in Lavaca County which involves drilling five more initial unit wells which we should have done prior to April-May timeframe and in general getting all of our acres held by production in both Lavaca and Gonzales Counties which would expect to have completed by the end of this year.
Before we discuss the details of the quarter, I wanted to touch on a number of recent developments which are significant for Penn Virginia. As we’ve discussed in the past, we have taken steps during the second half of 2012 through asset sales and equity offerings to improve our balance sheet and liquidity and had an undrawn credit facility and approximately $18 million of cash on hand at the end of 2012 for over $3 million of total liquidity. As a result, we expect to be able to fully fund our 2013 capital expenditures through cash, cash flows from operations and our revolver borrowings.
In addition, we are also considering the sale of a 3% interest over much of our acreage position in Lavaca County where at this time we expect to have 94% working interest since our quarter has not consented the majority of the initial unit wells in that county. This transaction would reduce any operational or any subsequent capital risks and improve liquidity further. But I want to point out that completing this transaction is not necessary to fund our 2013 CapEx program and the guidance which we’ll disclose and we will discuss today is not predicated upon the sale of this working interest.
At the end of the day, if we don't get what we’re considering accessible appraise we will retain a higher working interest in Lavaca County going forward. We have continued to increase our acreage position in the Eagle Ford and now we have about 33,000 net acres in approximately 300 remaining drilling locations, but we feel an approximate eight year inventory assuming a three rig ongoing drilling program.
Sequentially, as compared to the third quarter on a proforma basis to exclude Appalachia, production was up slightly and above the upper end of our guidance range. Core fourth quarter production was 15,444 barrels of oil equivalent per day compared to 15,245 barrels of oil equivalent per day in the third quarter excluding the effects of the Appalachian properties. As announced yesterday, our production for January was approximately 15,600 barrels of oil equivalent per day. At this time, we're just now beginning to see the benefit of that third rig in Eagle Ford.
Oil and natural gas liquid production increased to 56% of our total volumes compared to 53% in the third quarter and is expected to be over 60% of 2013 production. Oil production alone is expected to increase between 23% and 37% during 2013 as compared to 2012.
Total product revenues in the fourth quarter increased slightly and were $53.48 per barrel of oil equivalent prior to the hedges compared to $50.25 per barrel of oil equivalent in the third quarter. Oil and natural gas liquids were 83% of fourth quarter product revenues compared to 84% in the third quarter and are expected to be over 85% of our product revenues during 2013.
Adjusted EBITDAX was $62.3 million in the fourth quarter versus $61.2 million in the third quarter primarily due to slightly higher product revenues in spite of the sale of Appalachia and lower operating expenses. During 2012 Adjusted EBITDAX was $247.6 million and is expected to range between $235 million and $280 million during 2013.
Our gross operating margin per barrel oil equivalent remained strong increasing 15% from $34.11 per barrel oil equivalent in the third quarter to $39.29 per barrel oil equivalent in the fourth quarter due to our ongoing shift to oil and NGLs as well as lower operating costs.
The Eagle Ford Shale is a focus of our growth over past two years and will continue to be such during 2013 as we plan to spend approximately 88% of our total CapEx in this play. Steve will discuss the CapEx in a little bit in much more detail.
Our Eagle Ford Shale results remain excellent; along with the premium oil pricing we are receiving since we sale into the [OLS] market as well as ongoing emphasis on lowering capital and operating costs, we believe we have a very strategic acreage position within this leading domestic oil shale play and we are well positioned and continuing to grow our oil and liquids production.
As detailed in our operational update we reported year-end reserves of 113.5 barrels of oil equivalent, 40% of which were oil and NGLs and 41% of which were proved developed. Eagle Ford crude reserves increased to 161% from approximately 10 million barrels oil equivalent to 26.1 million barrels equivalent or approximately 23% of the total company proved reserves. The PV-10 of the proved reserves in Eagle Ford alone were about $600 million. If you look at the three play in Eagle Ford, at the year-end we are 70, about 70 million barrels of oil equivalent and over $1 billion with the PV-10. We therefore think we have significant room to continue to grow our proved reserves and value of the Eagle Ford alone. We also believe we can continue to add to our Eagle Ford drilling inventory due to the fact we have demonstrated we can continue to add acreage to our current position.
69 Eagle Ford wells are currently producing and include 54 wells in Gonzales County and 15 wells in Lavaca County. Three rigs are currently drilling in the play. Results of the recent wells drilled and completed were detailed in our January 29th operational release as well as details about our latest notable well, the Technik #1H which we disclosed in the earnings release, that well tested 1,136 barrels of oil a day and about 1.9 million cubic feet a day plunged with 2400 psi. This is a very good well and in fact is the best well we have drilled to-date in Lavaca County.
Our Eagle Ford production for the quarter was approximately 6,900 barrels of oil equivalent per day as compared to approximately 6,300 barrels of oil equivalent per day in the third quarter and averaged 30% oil, 11% NGLs and 9% residue gas during the fourth quarter. Due to the addition of the third rig late in the third quarter of 2012 we expect quarterly Eagle Ford production to continue to increase during 2013 and in fact it will make up about a half of our total 2013 production.
In Gonzales County our year-end medium PUD EUR is about 400,000 barrels equivalent. In Lavaca County that same statistic is approximately 500,000 barrels of oil equivalent. The projected EUR’s for our PUDs are based not only of course on nearby PDP performance, but also the anticipated lateral length on those PUDs. If you remember as of year-end 2011 our third party engineer had assigned a little over 300,000 barrels of oil equivalent for our PUDs in Gonzales County. So the well performance and our drilling results to-date reinforced increase in that $300,000 to $400,000 at the end of this past year.
As disclosed in our operational release, our seven most recent Lavaca County for wells averaged 21 frac stages a well had IP of 905 barrels of oil equivalent, a 30 day well had IP of 642 for the appropriate five wells. The Technik in Lavaca County was 18 frac stages and a well had IP of 1,445 barrels of oil equivalent per day.
I just want to remind everybody typically we hold much higher back pressures in Lavaca County due to the higher reservoir pressures in general than we see in that area. In Gonzales County, our six most recent Eagle Ford wells averaged 19 frac stages, a well had IP of 884 barrels of oil equivalent per day and a 30 well had IP of 609 barrels of oil equivalent per day for the appropriate four wells.
We continue to make operational progress in the drilling of these wells. During the fourth quarter of 2012, the average Eagle Ford well had 25 frac stages and cost little over $10 million. During the first nine months of 2012, the average well had 16 frac stages and cost about $9.7 million.
The increased costs, overall costs were not only due to the increased number of frac stages in the fourth quarter, but also due to the fact that the greater number of wells are drilled in Lavaca County which have a higher drilling costs than those in Gonzales County due to this intermediate string of pipe that we have to set.
We also had a few operational issues on a couple of Lavaca County wells which were mentioned in the press release and I'll get into a little more detail in that in a second. What really demonstrates our effort to reduce cost is on the completion side. The all in average cost per frac stage in the fourth quarter which was $289,000 whereas that same cost in the first three quarters was $369,000. This all in cost not only includes the pumping in chemicals and proppant costs that you typically think of as far as the frac job is there but also includes core tubing, perforating any wire line of plugs, flow back costs and labor.
This is a reduction of about 22% as 2012 progressed. So clearly, we are making progress on the cost side that I feel will begin to become much clear as 2013 program progresses. We continue to use only high strength white sand as profit in Gonzales County and a mixture of high strength white and ceramic in Lavaca County.
We continue to sell source our proppant, guar and acid, the fracs sell source in the guar they say it is $400,000 to $500,000 per well. We continue to take steps to reduce our costs which I think will be primarily driven on the completion side in 2013. One thing also important to mention but you will start to see us undertake more pad drilling as this year goes on, since much of our acreage is now held by production and makes a lot more sense for us to commence and start down spacing which will further drive some efficiencies and reduce costs further.
The operational problems that I mentioned previously included a few casing stream problems in Lavaca County which is we think is due to higher frac pressures we experienced which most tonnage you are pumping pretty close to 11,000. We have had some coupling issues. This is added to our fourth quarter costs. We recently upgraded to a new coupling. We think we have this problem behind us and therefore those additional costs we saw late last year should no longer be a problem in 2013.
We expect to stick with a three rig program and drill 38 Eagle Ford wells, about 29 net this year, with 22 gross 15.2 net in Gonzales County, the 16 gross 13.6 net in Lavaca County. With the three rigs, we can expect to continue to drill 35 to 40 gross wells per year. The stated goal of ours at a minimum is to maintain our multiple year drilling inventory by acquiring 4,000 to 5,000 (inaudible) on acreage annually at a total cost of $10 million to $20 million.
Over the past two years, we have clearly demonstrated that this can be accomplished. These 4,000 to 5,000 acres per year will replace the 35 to 40 wells we would drill annually with this three rig program. In fact in 2012, we picked up approximately 7,900 net acres in Eagle Ford alone.
We feel that over the next few years of maintaining this ongoing inventory of 300 locations with three drilling rigs is very achievable but having said that we will continue to review all the acquisition opportunities, primarily in Eagle Ford. And in addition, implement ideas of our new venture team that allows us to test our internally generated ideas and grow organically.
At that point, one of those early ideas as Pearsall Shale, just to bring you up to-date, we recently TD our initial horizontal test in the Pearsall in Gonzales County. We have just initiated completion work. I would expect we should have the results of that well sometime by the end of this first quarter.
So with that, I would like to turn it over to Steve Hartman so that he can provide an update of our financial progress in the quarter.
Thank you, Baird and good morning everyone. First, a quick note that you will notice now that we're reporting in BOE rather in Mcfe since our production and revenue have been greater than 50% derived from oil and NGLs for the last few quarters. We feel it’s more appropriate to report in barrel so that's how when we reporting in our 10-K and our earnings release going forward.
Product revenues were $76 million or $53.48 per BOE which slightly exceeded our guidance provided in the third quarter, revenues were up only slightly over last quarter upon per barrel basis. They were up 6% as we continued to increase our higher margin Eagle Ford production. You may recall cash proceeds from hedging are not include in our reported revenue number.
In the fourth quarter, we realized $5.5 million of cash proceeds, this equates to a $7.03 per barrel increase in our realized oil price and a $0.42 per Mcf increase in our realized natural gas price. Including the effective hedges, our realized oil price was $106.33 per barrel and our realized gas price was $3.83 per Mcf.
You can see we are benefiting from selling our Eagle Ford oil on the LLS market as Baird explained with our net back price this quarter at $9 above WTI. 83% of our product revenues were derived from oil and NGL sales. Operating expenses were down 17% this quarter at $20 million; this equates $14.19 per BOE compared to $16.14 per BOE in the third quarter, a 12% decrease in per unit cost.
This operating expense was a little higher this quarter primarily due to electing to complete from discretionary workovers in East Texas, that were expensed and from some higher environmental and water disposal costs. These were offset to some extend by achieving lower overall gas [NOE] cost due to selling our properties in West Virginia and Kentucky in the third quarter. The fourth quarter was the first full quarter where we saw the benefit of our lower gas NOE due to this sale. Gathering process and transportation expenses were lower primarily due to the divestiture of the properties that I just mentioned, offset by slightly higher cost and granite wash. Productions at (inaudible) Texas were 41% lower and $2.7 million this again is primarily due to the sale of the property and for tax rebates received in the fourth quarter.
Our taxes were 3.6% of product revenues compared to 6.1% in the third quarter. Cash G&A expense decreased 20% to $8.3 million this quarter, this is primarily due to having a $1.4 million restructuring cost in the third quarter related to closing our Pittsburgh office which we obviously didn't have in the fourth quarter.
And we did have a $1.7 million non-cash charge to G&A in our share-based compensation category and that's due to investing of some executive long-term comp related to reaching with retirement age and this was not in our 2012 guidance. Our gross operating margin and non-GAAP measure is generally defined as product revenues less direct cash operating expenses increased 15% or $5 per BOE over last quarter from $34.11 to $39.29 per BOE in the fourth quarter. These statistics do not include the additional favorable impacts of our hedges; this increase in our gross margin is a result of investment and continued growth in Eagle Ford.
Our gross operating margin in Eagle Ford production was approximately $80 per BOE in 2012 and that does not include any allocated G&A or hedges but you can see as we continue to ramp up our volume in Eagle Ford and decline up the lower margin natural gas, that company wide gross operating margin is continuing to increase.
Adjusted EBITDAX and non-GAAP measure which is generally EBITDAX with the cash proceeds of hedges included was $62.3 million for the quarter which is 2% higher than last quarter. As Baird mentioned, this is our sixth consecutive quarter with adjusted EBITAX over $60 million.
Our loss attributable to common shareholders for the quarter which includes the effect of deducting $1.7 million of preferred stock dividends was $56.1 million or $1.05 per diluted share. This was impacted by a $75 million pretax impairment of our Marcellus assets, which is a result of the write down due to lower gas prices in our Marcellus properties.
Adjusted net loss which excludes certain non-recurring items such as the impairment and is reconciled in the press release was $0.22 per diluted share. Capital expenditures for the quarter were $118 million up from $85 million in the third quarter. For 2012 we ended the year at $385 million of CapEx, which is $34 million higher than the top end of guidance we provided in October and $41 million higher than in midpoint.
The primary driver of the increase as Baird explained is the pick up in working interest in Lavaca County acreage which was about $14 million for the quarter. We also accelerated the completion of three wells in December which had been scheduled to be completed in January; that was about $7 million. We added approximately 1000 net acres to Gonzales from Lavaca County beyond what was anticipated. So that was good news and that's about $3 million and we also had some longer well laterals and originally planned some operational litigation issues as Baird explained and all of those together and in addition with the Pearsall test it was about $17 million.
Moving on the capital resources and liquidity. At year end we had nothing outstanding on our $300 million credit facility at $18 million of cash on the balance sheet. Currently we have $28 million drawn on the credit facility, $4 million in cash and $2 million in letters of credit outstanding for $274 million of liquidity. Our 2012 adjusted EBITDAX was $248 million and our total debt-to-adjusted EBITDAX ratio or leverage was 2.3 times compared to our permitted covenant in the credit facility of 4.5 times. We have plenty of room within that for borrowing capacity.
Our next borrowing base redetermination is coming up in April. We've not yet provided any data to the banks regarding the redeterminations. So it’s too early to tell what our borrowing base will be this spring, but from what we know so far we expect it to be no less than what we currently have.
Moving on to hedges we added some natural gas hedges and oil hedges since the third quarter call. Our current position by quarter is detailed in the earnings release. We currently have hedged 4600 barrels per day of oil production for 2013, which is about 58% on the midpoint of guidance. The weighted average for price of our portfolio is $97.35 per barrel which is a blend of our callers and our swaps.
We have $20 million a day hedged of natural gas for ’13 which is 55% of the midpoint of our guidance and the weighted average forward price of that portfolio is $3.76 per MMBtu. And now on to our 2013 guidance which is detailed on page 10 of the release. Our current guidance does not include any effects of the JV process in Lavaca County. We will release updated guidance that the JV interest sold and as Baird mentioned our ability to fund the 2013 capital program is not dependent on this sale.
Our guidance for capital expenditures is relatively flat to 2012 actual, with spending at $360 million to $400 million. Drilling and completion is approximately 85% of expenditures and about 90% is spent in the Eagle Ford. This acquisition includes leased dollars to replace our current drilling inventory at an average cost of $2500 to $3000 per acre. We have approximately $15 million allocated to new ventures development and about $6 million to finish our initial testing of the Pearsall.
Capital is about $50 million to $60 million higher in our preliminary guidance given in October, primarily due to our higher working interest in Lavaca County. Basically, we're going from a 57% working interest to a 94% working interest on our non-consent wells. We're planning for some longer laterals and pipeline extensions on the Lavaca County acreage and that's offset by lower exploration dollars and lower spending in the Granite Wash.
If we sell the 40% working interest we have in market currently, we expect our capital requirement related to the lower working interest will decrease about $50 million to $60 million. That does not include any sale proceeds or assumed carry. Our adjusted EBITDAX we sell this asset will decrease about $25 million to $30 million and of course we cannot give you any assurances of a deal closing or the ultimate proceeds or the deal structure, we will update guidance if and when we get a deal signed.
Production guidance is 5.7 million to 6.2 million barrels equivalent or 15,500 to 16,900 BOE per day. Year-over-year, the midpoint is roughly 3% higher than 2012 actual, pro forma for the 2012 property sale. We expect oil production to grow at 23%, 37% over 2012 volumes with 30% growth at the midpoint. We expect oil and NGLs together to comprise 60% to 65% of our total production in 2013 compared to 48% in ‘12 and 56% in the fourth quarter.
Production growth was impacted since our preliminary guidance in October, primarily due to lower drilling in Granite Wash and by accelerating from 50% working interest Eagle Ford wells earlier in the 2013 drilling schedules. Product revenues are expected to be $330 million to $364 million in ‘13. Revenues derived from oil and NGLs are expected to approximately 87% of total product revenues.
Assuming a 90% oil price and a $3.50 gas price for 2013, we would expect to receive about $13 million in cash proceeds from the hedges we have currently in our portfolio. For LOE we are guiding to a flat cost of $4.80 per barrel at the mid point which takes in to account lower LOE as a result of the property sale offset by higher LOE for Eagle Ford oil.
For adjusted EBITDAX which includes cash received from hedging, we assume the $257 million mid-point of the given range. This is based on our price assumption $90 oil and $3.50 natural gas for ‘13 as I already explained. Assuming the mid point of this guidance range, adjusted EBITDAX grows 3% over 2012, pro forma to adjust for the contribution from our sold properties the growth rate is approximately 7%, and this may seem like a smaller growth rate than expected, but I assure you the cash flow from our base operations is going. There was some significant drivers of cash flow in 2012 that we are not assuming in this guidance.
Specifically we realized the significant LLS premium to WTI which I mentioned earlier. It was $9 a barrel for the fourth quarter net of transportation. We are not assuming this higher premium in our 2013 guidance, although we have been seeing it in the first two of this year.
We are also not forecasting as much hedging proceeds. In 2012 we realized $30 million in cash proceeds from hedging, which is included in adjusted EBITDAX. For 2013, we are assuming $30 million that I just explained and we do plan to continue to layer in hedges just like we did in 2012 that our budget prices are higher as the market allow us to, and of course if we start layering in those hedges it will cost $90 that will adjust our adjusted EBITDAX guidance, but that’s currently not in our guidance.
That concludes the guidance review.
Thanks, Steve. Thanks for all the detail. In conclusion we continue to execute on a, we feel as a viable strategy and we did only to demonstrate that we can grow oil, NGL production and of course our oil reserve. We believe that we’ve got a very strategic, very viable Eagle Ford asset that we can grow and have grown. We got multi-year drilling inventory that some folks are being concerned, but we are not concerned about that, and I also convinced with focus on our cost that you are going to see go down in 2013.
I also think that you are going to see improved results with the down spacing, with zipper fracs those kind of benefits that you will typically see, as you go back in and drill some of the better areas of field. I feel very confident that we are going to see improved results as year goes on also.
And with that April, I would like to open the lines for any questions, please.
(Operator Instructions) And we will go first to Neal Dingmann of SunTrust.
Neal Dingmann - SunTrust
Baird you sort of addressed this. I am just wondering, again if you don’t get the price yield on for some of that Lavaca acreage, will you just continue with the three rig program throughout this year and then revaluate it at the end of next year is that sort of the plan?
Yeah, we would Neal, at the end of the day; we try to because we have been so focused on liquidity that we were concerned about the Aspen issue. But having said that, if you keep that in interest and associated growth in production and resulting EBITDAX you essentially pay out that incremental CapEx with that additional working interest in a fairly short period of time because of the quality of the wells that we are drilling. So the pros and cons of either sticking with it or doing it alone, and if we don't get something it just makes a tremendous amount of sense to us we are just going to keep doing it alone.
Neal Dingmann - SunTrust
Okay. And then just lastly not outside of the Eagle Ford, any lease issues there; I mean now that you've obviously diverted most of your CapEx to the Eagle Ford that we should look at Granite or the Marcellus?
No. Everything we have in the Granite Wash, almost everything we have in the Granite Wash as far as the development area is HBP; really the focus is on just doing what we do you know. If we were forcing it up to have a discovery in the Pearsall, I think you would see us uptick that leasing effort, even though we've got a substantial position where we are already in this liquid part of the window; I think you would see us go out there and step up our leasing activity if that Pearsall was outstanding well. So in any case right for right now we are just focused on the Eagle Ford.
Brian Corales, Howard Weil.
Brian Corales - Howard Weil
Just to kind of tackle the Pearsall question, is your plan just to complete the well, test and see how it flows and then decide what else you are going to do for 2013 or do you all plan to drill another well already?
We do not have a second well in the budget right now. The plan would be just to sit back and evaluate what we have Brian. If it’s something that's outstanding I think you would see us probably jump on and try to get another well drilled this year. From an acreage standpoint, we probably would want to pause and shore up our acreage position in the play before we do too much, because we even though our acreage position is okay, we always want to make it bigger if you can and there's reasons that we think we could make it bigger if we are successful. So I think you see us take a pause at least and then probably try to get a well drilled, second well drilled sometime later on in this year.
Brian Corales - Howard Weil
Okay. And then in the Eagle Ford I mean you are developing I'm assuming - what are you all assuming now on a down space and we've seen other operators talk about 40 and 50 acre down spacing, where you all sit today and then your 3P number that you gave the 70 million barrels and a $1 billion of PV-10 did that just assume 80 acre spacing or what did that assume?
Both; we had some parts of our lease hold on larger spacing, some parts that we could just buy right now on down spacing; John why don't you take that question if you don't mind?
Sure. And where we have the most wells drilled will be in our Gonzales County we've got 54 wells drilled there so we've got a certain amount of confidence in down spacing that down well below a 100 acres, whether or not we get to 40s another matter, but I think its safe to say the 60 to 80 range that's a very viable infill. In Cheniere, where we've only got 15 wells drilled, all our initial wells are drilled on 700 acre units. Those have substantial room for additional down spacing and probably will ultimately end up in that same range that we would forecast for Cortez being in that 60 to 80 to 100 acre spacing, just depending on the geology and the unit outlines.
Brian Corales - Howard Weil
And just the 3P number of 70 million barrels, was that you all just used the conservative 100 acre spacing for that?
Go ahead, John.
I will go ahead and let you answer that if you want to, Baird, but I think that’s going to reflect the 3P location count that we have, which is around 300; under the infill spacing that we described and I can’t give you one infill spacing that is ubiquitous across all our prospects because it changes, but there is 300 drillable locations in our 3P inventory which is what that 70 million barrels is based on.
Brian Corales - Howard Weil
Okay. So on 30,000 acres, that’s roughly about 100….
I would say that’s right, some part of the acreage end up not being able to utilize entirely just because of how these things look. Some of these leases were formed, but I would say a good average. If I have to guess, we will probably be 90 to 100 acres run.
Ray Deacon, Brean Capital.
Ray Deacon - Brean Capital
I was wondering if you could talk about any changes to your Eagle Ford and any potential for what well cost reductions from here?
Let me talk about the reserves; I will turn over the well cost issue to John. You know, we went from 300, little over 300,000 to 400,000 in the Gonzales County as of year-end 2012. Lavaca County, we always have that 500 or third-party engineers also at 500. So we're consistent there. There is a room to improve it. Yeah, I think there is; I mean I can’t tell you exactly what it may go up to but its dependent upon longer laterals, there are different parts to the Eagle Ford it may make sense to drill as far as the placement of lateral in better places than others across our acreage position, we are still trying to get our arms around that we improve results. There is also the case be made that is also important to stand as high resistivity zone even you have to slow down your drilling just a little bit. We saw that with this Technik well standing at high resistivity zone, we ended up with a much better well the best well we drilled to-date on Lavaca County. So even though, I don't want to call this a mature play from where we are because we are still learning and we think we can make improvements on the results of these wells.
As far as the cost goes John, why don't you jump in on that please?
You bet, and Baird brings up a good point about the maturity of the play I mean we drilled 54 wells in Gonzales and just 15 in Lavaca County so this has been a learning curve for us. In Gonzales, we have a 3D survey and in the Lavaca County that 3D survey is currently been shot. We don't have it in hand yet, we expect to have that in the late second quarter. And that will help in the steering place of these wells, but on the 15 wells that we have drilled, there is not a lot of science wells, pilot holes to gather the subsurface information and we just about got the science wells behind us, I think in the first quarter of this year of 2013, we had two more pilots, including a full core in one of those. So in first quarter of ‘13, you will see some still the elevated drilling cost in (inaudible) as we do our science wells.
Going forward, though and getting away from the science wells and trying to get it more on a manufacturing type play where we are doing pad drilling with the closer space wells and frac and getting the completion efficiencies that we anticipate, we are anticipating seeing probably an 8% to 10% reduction just on the pad drilling, on overall cost, also we have been wholesale buying our guar and proppant and acid and trying to drive those completion cost down and on the stimulation side, we have got the stimulation contract that rolls over in July. So I think the market has soften quite a bit and that contract roll over help us, and we hope to see an additional 8% to 10% on the completion side probably in the third and fourth quarter.
So we will probably see some direct results in the cost reduction starting to show up in the second quarter but the third and fourth is when we anticipate seeing the real big change.
Ray Deacon - Brean Capital
And I guess just what really explain the increase in the oil guidance as the percentage to the overall Bcfe in ‘13 was that Gonzales or Lavaca or?
This is Steve. It’s been mostly an increased in the Lavaca drilling; it’s due to the pick up in the working interest that’s the primary driver of any increase in the oil.
Ray Deacon - Brean Capital
Okay, got it. And just one last quick one, Steve, could you go over what exact projects are the mid stream dollars going for this year?
Its primarily for building out gathering systems for the natural gas out to the various fields, and since we have been trying to drill to hold these non-consent wells and hold acreage, we have to spend more dollars for facilities and pipelines than we normally would because we are building out the base infrastructure for the whole play, and of course as we go back after everything has been earned and held by production then we will have less facility cost going forward. So it’s an initial investment in the infrastructure for the entire play.
(Operator Instructions) We will next here from Welles Fitzpatrick of Johnson Rice.
Welles Fitzpatrick - Johnson Rice
I think if I remember correctly you guys have been non-consented in about 17 units as of the last update, what's that number looking like now?
John you have that answer.
All of them, I think the total number is 21 or maybe 22, I think there is still one unit that have yet to be completely formed but we have sent the election to our partner who has non-consented all of those and elected to maintain their override and they've expressed their satisfaction with the way the project is proceeding.
Welles Fitzpatrick - Johnson Rice
So then that whole 21-22 adds about and I know you guys talked about I think its 4,200 net acres being added previously but that allowed maybe 4,500 to 5,000, something in that neighborhood?
I think that's probably a good estimate.
Welles Fitzpatrick - Johnson Rice
Okay, perfect. And then on the Pearsall, how many stages are you guys looking at with that design and what's the [AFE] looking like?
We've got I think 18 to 21 stages on this, we are going to try a couple of different things, you know we are in, this would be the most northeastern extension that we know of where the Pearsall has been tested horizontally. So I don't want to commit to one single completion methodology. So we are going to try a few different things. Overall, I think we will have somewhere between 18 and 21 stages when it’s all said and done, some will have shorter stage links and other some will have longer, we are going to have radioactive trace it and see what performs best.
On the capital side, we did have to supplement that AFE primarily because of the on the pilot hold and getting kicked off as very deep well so I'd be guessing I don't have that AFE number in front of me. It’s someone in (inaudible) may have it. It’s a large number. But I think on a going forward basis, we would anticipate our Pearsall wells to have a capital cost similar to what our Lavaca County Eagle Ford wells look it.
John, it's about $10 million to $12 million for that, for the submission tests.
Steve Berman, Canaccord Genuity.
Steve Berman - Canaccord Genuity
Most of my questions have been answered, just one other one, Baird where do you anticipate spending the rest of the CapEx outside of the Eagle Ford and Pearsall from time-to-time in the Mid-continent you've done some exploration testing, what's in the budget for anything like this year?
Well, we have a handful of gross wells in the Mid-continent, Granite Wash, the we talked about the mystery money, the bulk of the other dollars is actually with our new ventures team. We have allocated I think $10 million on the land side for the new ventures team and another few million dollars on seismic and data in general to drive that we have not put any wells in there for exploration this year other than the Pearsall. So if we get to the point that we are ready to drill a new ventures well then we would consider it, it has to stand on its own two feet by the end of the year. But at this time we've got just leasehold dollars to going and start picking up the acreage.
And next we will hear from Justin (inaudible) of RBC Capital Markets.
I am going to talk a little bit about this in your opening remarks, but can you give us some more color on the timing of drilling program and how the rigs might move on the Lavaca and Gonzales County?
John, why don’t you answer that question please?
Sure, we will continue to under our current drilling schedule drill the remaining wells that we have scheduled for the initial unit wells in the Cheniere. That should give us a total of 16 wells in Cheniere and the remainder of the other 22 wells would be drilled in Gonzales. We have the option of going back and doing some additional pad drilling in Cheniere, but we’ve also got a JV with another major company in Gonzales that we need to go split some JV wells within later in the year.
I think Baird alluded to that early in his call where there are some 50% well that we're going to get drilled in Gonzales County as well. So right now its 16 wells in Lavaca and 22 wells in Gonzales, but that could change in terms of actual numbers between the two.
(Inaudible) with Raymond James.
Got in a little late, if this has been asked really I apologize. As far as the geology as you will see involving the Pearsall, what are they offset about the Lavaca County, and do your properties there include potential for Pearsall as well.
Well, it would probably be gassy too gassy in Lavaca County also probably prohibitively deep and expenses, but it would be dry gas in Lavaca County. So at this time we are not recognizing any value for the Pearsall and Lavaca County.
Are you still seeing the 500,000 EUR in the Lavaca County, is that the updated guess at this time.
And our final question for today will come firm (inaudible).
In terms of the firm transportation commitments has all that now been charged off.
We have charged everything off in West Virginia associated with our sale of Appalachian. We still have firm associated with the Marcellus that we still have standing. We continue to sell that firm on a month to month basis, but we still have some firm there.
But everything that's basically not going to be used on a go forward basis, I mean I'm assuming the Marcellus is blowing it up to where that you can still sell that if you are not using it for existing production.
That's correct. We may not get full market rate but we can sell it.
Yeah, you can sell, but the charges should be relatively deminimus compared to what's been taken.
Yeah, we have firm on national fuel and we have some firm on Dominion and it kicks in later on this year, the firm on national fuel is fairly insignificant cost.
And in terms of the rest of the gas reserves are there any leases there that need to be drilled on for HBP purposes or is pretty much everything held now?
Almost everything is held and on the Mississippi stuff is almost all held. We have some things in east Texas associated with the Haynesville specifically that selectively, we may let expire when we may let to renew, just because we do have a very good area in Haynesville just doesn’t makes sense to drill today, but at some point in time, we think it will. So we may want to try to preserve some acreage it’s not HBP and the Haynesville but again most of that is HBP.
Okay, fair enough, and then final question, obviously the big guy down in Eagle Ford he comes out and says we’ve got drilling these Gonzales wells that are (inaudible) at 6000 plus, we are going to see anything like that?
I am never going to say never, but with the big guy as you are referring to, they have a very big, geological reasons why they have those very, very good will as is very thick Eagle Ford probably 400 to 500 feet thick. Where we are is typically 140, 150 foot thick. So there is geological reason why they are seeing those kind of results, but it would be unlikely for us to see those kind of results.
And Mr. Whitehead, you have any closing comments.
I do not. I appreciate everybody listening in. Look forward as this year goes on, we think we are making a lot of progress and thank you for listening in.
And that does conclude today's conference. Thank you all for your participation.
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