Penn Virginia Corporation
Q1 2013 Earnings Call Transcript

Published: 9 May 2013

[Operator:]

Good day ladies and gentlemen and welcome to the Penn Virginia Corporation First Quarter 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this call maybe recorded. I would now like to introduce your host for today's conference Mr. Baird Whitehead, Chief Executive Officer. You may begin.

[Baird Whitehead:]

Ashley, thank you and good morning. I would like to welcome you to Penn Virginia’s first quarter 2013 conference call. I am joined today by various members of our team, including Nancy Snyder, our Chief Administrative Officer; John Brooks our Executive VP of Operations; 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 Form 10-Q, which we both filed last night will apply to our comments this morning. First of all, as you know we recently closed on our acquisition of the Magnum Hunter Eagle Ford assets which we think overtime will be truly a transformational event for us. We now have approximately 80,000 gross, 54,000 net acres in the core area of the volatile oil window in Gonzales and Lavaca Counties and we're able to keep adding acreage to this position. We also now have approximately 645 gross, 420 net drilling locations or about in a year inventory utilizing six rigs. And we expect to be able to add to this inventory not only with additional leasing, but also because we expect the contribution from an upper Eagle Ford zone that we recently tested that exist across some part of our acreage position and I'll talk about this in a little bit more detail in a minute. We currently have five operator rigs with two non-operator rigs, drilling, but soon to be, we will reduce that two four operator rigs and two asset operator rigs for a total of six. Post closing, we now expect to drill up to 68 gross, about 43 net wells this year, 35 gross to 17.3 net of which will be on the Magnum Hunter acreage that we acquired. And assuming ongoing six rig program in 2014, we should drill about 75 gross, 46 to 47 net wells per year going forward. During the first quarter of ‘13, combined with Magnum Hunter we produced about 10,000 barrels a day equivalent from the Eagle Ford itself. During the last nine months of 2013, we should average close to about 13,000 barrels a day net equivalent per day. Company-wide and just oil, we expect to produce about 11,500 of oil per day during the final nine months of this year versus 6,700 barrels oil per day for the first quarter, bringing the 2013 total to 3.8 million barrels of oil which is about a 70% increase year-over-year. Company-wide, we produced a total of about 15,900 barrels a day equivalent per day during the first quarter; with the expectation to average during the last nine months about 20,200 barrels a day equivalent. So you can see the effect of the ramp up in drilling and the addition of the Magnum Hunter assets. Proforma year-end 2012 proved results for the company were about 126 million barrels, 30% or 38 million barrels of which were in Eagle Ford alone and as one way to expect we will experience ongoing growth in our proved oil reserves and we will therefore benefit with increases in our (inaudible) base as the year progresses. Using the year-end 2012 pricing and proforma proved reserves our PV-10 from the Eagle Ford Shale alone was $844 million, $551 million of which was proved developed, with a significant probable and profitable Eagle Ford inventory of roughly 530 gross and 345 net locations, the proved reserves valued at Eagle Ford and the company of course will only continue to increase. Debt capital markets had a very positive reaction to our Magnum Hunter acquisition and we were able to upsize our placement of our 8.5% senior notes in 2020, about $400 million which was our original intent to $775 million. This upsizing also allowed us to repurchase the $300 million at 10.375 notes that mature in 2016. So we have therefore extended all of our note maturities after 2019 and 2020, and going forward has saved about $4 million a year in annual interest payments. Proforma for the transaction, we had approximately $280 million of liquidity with a leverage ratio of 3.4 times at the end of the first quarter. Later this month, we expect our borrowing base to increase by approximately $45 million to $75 million to a total of $320 million to $350 million, which will then fully reflect the reserves associated with the acquisition and further boost our liquidity; Steve will give you little bit more detail on this in a few minutes. As the cash flow from the growing oil production continues to increase and with an anticipated capital program going forward at a similar to or less than 2013, we have spend and therefore our borrowings under the revolver are expected to continue to decrease as time goes on, in fact our goal by late 2015 and entering in the 2016 is to be able to self fund our capital program. We expect to be able to fully fund our 2013 capital expenditure program through cash, cash flow from operations and or revolver borrowings. And we are also considering some asset sales probably at the end of 2013 or early in 2014 to further improve liquidity. One thing I need to point out that we really have not talked about today is in both Gonzales and Lavaca Counties and we have other working interest in our legacy Eagle Ford acreage. Our AMI’s with those work interest owners require as offer them the proportion interest of the Magnum Hunter assets. If all of our existing partners exercise their preference are rights to purchase under those AMI’s our purchase price or the $400 million would be adjusted down by about $70 million. This of course would resolve in approving of liquidity and we would end the year with slightly better credit issues --credits, just excuse me. We should know the result of (inaudible) by the end of this month or early June and it be will our plan once we know exactly what our final interest are, we will put out some interim guidance to take it and look out versus waiting until the second quarter. The first quarter of 2013 continued our positive trend of solid results achieving our seventh consecutive quarter of EBITDAX of $60 million and greater on our legacy assets. With the Magnum Hunter acquisition and excellent year-to-date drilling results from both our existing and acquired assets we expect this positive EBITDAX quarterly trend to improve during the balance of 2013 and beyond. Year-to-date operations, we’ve had a number of positive developments which I would get into this morning detail. First of all, which is important for us, we have completely derisked our Lavaca County acreage position was now includes Magnum Hunter acreage. We believe all of this acreage included in the original 13,500 acre format that we negotiated late in 2011 is prospective now for development drilling. Under the terms of the format we now only have one well left to drill in order to earn all of the-non consent acreage associated with original drilling units in Lavaca County. In addition to this, a majority of this acreage has been HBP; we have already begun our down spacing program on this acreage. Associated with this down spacing effort the major company from which we obtained the original format has decided to participate in a second well and one of those original units in which they have working interest. I think this is worth noting since there appear to be a concern of the market, by the market of why that partner have backed and left to go non-consent on any wells proposed after the first five. I think this only confirms that this was not necessarily well results that caused that decision. Also mentioned in the press release were the details for two wells recently drilled in Lavaca County which gives us reason to be excited about what we have in that County. Both of these wells were drilled in the far eastern portion of the original format acreage. The Martinsen well which was one of those wells was drilled in the far southeastern portion of the acreage and tested almost 1,900 barrels a day equivalent. That’s the second best Eagle Ford well we have drilled across all of our acreage in both Gonzales and Lavaca County; it was somewhat gassier as one would expect, but the oil content alone remained intact and it tested almost 1200 barrels a day just oil. Next we drilled horizontally in an upper Eagle Ford interval in the far eastern portion of the same acreage. The [frac stage] well which we had in the table tested 1200 barrels a day equivalent in this upper Eagle Ford zone. This is a new zone of completion for us since typically we drilled laterally in the lower Eagle Ford interval which is about 100 feet deeper and is typically described by the industry as its high resistivity interval. The IP of this well assuming our typical type curve would match in approximately 500,000 well. We've only had this well unlocked for a little bit less than two months, so we need to course some additional production information to confirm the reserves. We also need to confirm that in fact it is completed separate reservoir and will take some additional drilling to do that. We also want to substantiate how extensive it is across all of our acreage and right now we are actually drilling a follow up well in the same upper Eagle Ford zone in Gonzales County, some distance away from this high [stake] well. If we can confirm this upper Eagle Ford potential, this certainly would add to the 645 locations that we already have in our current inventory with no additional land costs since this zone being part of the Eagle Ford is already been HBP. One way we have figured out what this zone is, we drilled some pilot wells we have talked about in the past, ran some open-hole logs. This upper Eagle Ford has always had some good mud log shows as we drill through it and the open hole logs confirm the porosity. It’s also a calcareous interval, easily fracked, sort of a transitional kind of zone between the Austin Chalk and the Eagle Ford itself. We are also continuing to add to our acreage position in Lavaca County in addition to the original farm-out acreage in the Magnum Hunter Lavaca County assets. We have added within the last year or so about 2,800 net acres and have another 4,400 net acres in the (inaudible) and would have been pick up much of this acreage from anywhere from a $1000 to $1,500 an acre. Moreover, the results for the most recent wells drilled and completed were detailed in our release with the average initial and 30-day rate substantially higher than the average for the prior wells. In general, this can be attributed to longer, lateral lengths, therefore more frac stages as well as a fact that a lot of these wells are drilled in Lavaca County where we have higher reservoir pressures. Going forward, many of our wells in Lavaca County will also have these longer laterals. Also important to mentioned is the initiation of our down-spacing and we made reference to two pads that had been drilled in the first quarter and completed, one of which was a two-well pad, the other which was a three-well pad. The results of these five wells were drilled on about 70-acre spacing and were among the best. As pointed out in the press release, we also recently started to flow back with another three-well pad on approximately 70 acre of spacing and each of these wells right now are raising about 1,000 barrels a day and about 400 Mcf a day. Going forward, since much of our legacy acreage is now HBP, we will continue our development program more so with that drilling and drilling on shallower spacings and therefore we will see some cost benefits because of that. Importantly as mentioned in the press release, our focus going forward will be to reduce our Eagle Ford drilling and policing cost and at a minimum, we expect to reduce these completion cost by about a $1 million to $1.5 million a well and on the drilling side, another $200,000 to $500,000 a well, again associated with pad drilling. And lastly, we discussed in the press release the results of our first Pearsall shale well. The test of 992 Mcf a day to 140 barrels of oil a day and was recently turned in line. This clearly is less of a rate in gas here than we had hoped and we view this actually as a positive data point, and we’ll use this information to determine where we go from here. One option would be to go downdip where higher reservoir pressures, and therefore higher production rates would be expected and really would be similar to what we have seen in Eagle Ford between Gonzales and Lavaca Counties. One other important filing that we found out is the gas in oil from the Pearsall where we are is actually sweet. We were originally concerned that it could be sour. But for the time being we are going to continue to gather production data with the intent to possibly drilling another test well probably in 2014. So with that I would like to turn it over to Steve, so that he can provide an update of our financial progress through the first quarter.

[Steve Hartman:]

Okay thanks Baird, and good morning everyone. I will start with a brief financial review of the first quarter results, and first thing to know our financial results in the first quarter do not include any other facts of the Magnum Hunter, Eagle Ford acquisition, that transaction closed on April 24th, so our production, capital investment, cash flow impacts prior to that date are treated as a purchase price adjustment. You will start to see results of the acquisition on our financial results in the second quarter. Product revenues were $82.2 million or $57 in a $0.61 per barrel oil equivalent, up 8% over the fourth quarter of 2012. The increase was driven primarily by higher oil volumes and higher realized oil pricing, offset partially by declines in natural and NGL volume in pricing. Oil and NGL revenues were $70.2 million, which is 11% higher than in the fourth quarter. Oil and NGL sales were 85% of product revenues for the first quarter. Our realized oil price was a $105.28 per barrel, which was 6% higher than the fourth quarter, including the cash settlements from our hedges, our realized oil price was $109.97 per barrel. We received $3.6 million in cash settlements from our oil and natural gas hedges during the quarter, and as always is the case, cash derivatives settlements are not included in our revenue. Oil expenses were $7 million higher this quarter, LOE alone was 1.2 million higher primarily due to an increase in chemical cost related to the purchase of paraffin inhibitor nearly because of the colder temperature in the first quarter. We also had significant chemical and R&M expenses related to corrosion control associated with H2S in the natural gas stream. These two items were about half of the extra expense. We also had some significant road maintenance work needed in the first quarter. Gathering, processing and transportation expense increased $1.1 million this quarter; about 600,000 of this is a one-time non-cash adjustment related to the Appalachian Basin sales last year. The remainder is due to cost related to purchasing higher volumes of Eagle Ford gas which company-wide is a higher rate than the rest of the gas. Taxes were higher during the quarter due to increased contribution of Eagle Ford oil which is taxed at a higher rate. G&A was higher due to the payment of 2012 bonuses and related taxes and benefits in February, which exceeded our 2012 accrual. Our operating margin, a non-GAAP measure that’s generally defined as product revenues less direct cash operating expenses was $35.88 per barrel of oil equivalent company-wide. Operating margin was down slightly from the fourth quarter due to higher expenses that I just described, but our Eagle Ford margin remained strong. Our cash margin in the Eagle Ford was $78.75 per barrel in the first quarter and not including any allocated G&A or hedges. Adjusted EBITDAX and non-GAAP measure, that’s reconciled on page 10 of the release was $60.3 million, and as Baird mentioned that was our seventh consecutive quarter of being at or above $60 million. Our loss attributable to common shareholders, which includes the affect of paying $1.7 million of preferred stock dividends was $18.1 million or $0.33 per diluted share for the quarter, and our adjusted loss attributable to common shareholders which adjust for the non-cash impacts of hedging, our gains or loss, gains or loss on sales, adjustments from income taxes or other adjustments disclosed on page 10 of the release was $10.4 million or $0.19 per diluted shareholders. Capital expenditures for the quarter were $96 million down 19% from the prior quarter. We spent $87 million or 91% of the capital on drilling and completion activities. We spend about $5 million on leasehold primarily in Lavaca County. Moving onto capital resources and liquidity; at quarter end we had $638 million of debt outstanding, which consisted of $600 million of senior notes and $38 million drawn on the revolver. We reported financial liquidity of $273.6 million and leverage up 2.5 times, we are trailing 12 months of adjusted EBITDAX of $243.7 million. Pro forma for the acquisition that was $1.075 billion, cash was $5 million, liquidity under revolver was $275 million which is current borrowing base; we had nothing drawn on the revolver pro forma for total liquidity of $280 million. Pro forma trailing 12 month of adjusted EBITDAX was $316 million and pro forma leverage was 3.4 times. The borrowing base was adjusted down about $25 million with the issuance of the new bonds, but we don't expect it to stay there. Our borrowing base in the redetermination process right now, Wells Fargo our lead bank launched the redetermination with the bank group yesterday with the proposed borrowing base of $350 million. Wells Fargo received approval at their banks to take the commitment to as high as $60 million, which is higher than their current allocated commitment to cover any minor shortfalls that might happen within the bank group. Because of this, I feel confident our borrowing base will be approved at a minimum of $320 million or probably closer to $350 million. And at this point, I don't see any reason why the bank group wouldn't approve the proposed amount, but we won't know that for sure for about another two weeks. Moving on to hedges; as we've been emphasizing out on the road, we aggressively hedged our existing volume in the first quarter in anticipation of leveraging up for the acquisition. We took our hedged volume up prior to closing to the 70% of anticipated volume for both oil and natural gas in 2013 and to about 35% in 2014. Once we close the acquisition, we hedged another 2000 barrels per day of oil for both 2013 and 2014, taking our overall portfolio to about 66% hedged for 2013 and about 35% to 40% hedged for 2014. Our goal at these latest hedges was to protect our acquisition economics, which we assumed $90 per barrel WTI on about two-thirds of the volume for both ’13 and a little bit for ’14, about third for ’14. We've achieved that now and we feel we are in a good position with our hedge portfolio. And moving on into guidance which is provided on page 11 of the release, the guidance takes into account the contribution for the acquired Eagle Ford assets as of the closing date on April 24 and remember that any financial activity prior to that closing date treated purchase price adjustment, so these are not pro forma annualized numbers for 2013. The only place where we would have an annualized number is with our reported leverage where we are allowed to take into account pro forma adjusted EBITDAX per our credit facility for a trailing 12-month period. Capital expenditures are expected to be $445 million to $505 million, compared to earlier guidance of $432 million to $482 million. The primary difference is the change in assumed closing date where we now have three more weeks of capital to account for. We had been assuming a May 15 closing date. We also picked up about 1.5 net wells in the drilling schedule related to moving toward pad drilling. We also had some higher incurred cost for the [Persol] test that we took into this latest guidance and this was partially offset by assuming lower completion cost for our operated wells on our legacy acreage in the second half of the year as Baird described. Production guidance is 6.7 million to 7.2 million barrels of oil equivalent or about 18,250 to 20,000 barrels of oil equivalent per day. This is higher than our previous guidance as you would expect with the earlier closing date, but it also takes in to account the strong results from wells we just brought online as Baird described. At the midpoint of guidance, we're expecting 7% year-over-year volume growth for total production and approximately 70% year-over-year growth for oil volume production. We expect our fourth quarter 2013 oil production rate which I am using at a proxy for a year-end exit rate to be approximately 12,500 to 13,000 barrels per day. This would be about double the rate that we produced in the fourth quarter of 2012. Product revenues are expected to be $340 million to $385 million for 2013, with about 88% of it derived from oil and NGL sales. Again this is slightly higher than our previous guidance consistent with the earlier closing date and this does not include any cash settlements from hedges. Assuming a $90 oil price, $4 natural gas price for the second quarter and $4.25 natural gas price for the second half of the year which is our assumed price deck, we would expect to receive about $13 million in cash proceeds from hedges. We are guiding higher for LOE for 2013. The primary cost for the increase is the Magnum Hunter uses ESPs for artificial lift which is more expensive than the gas lift method that we use. Until we fully understand their wells and what we want to do going forward, we are guiding towards the higher cost, but we should get a hand along these two go forward costs over the next quarter or two. We are also adding some additional LOE money for corrosion and paraffin control in Eagle Ford as I explained earlier and adjusting for some higher [R&M] cost based on our experience in the first quarter. For adjusted EBITDAX which includes cash received from hedging, we are increasing our guidance slightly to $300 million to $360 million. Again, this is not pro forma for about 3.5 months of EBITDAX prior to closing and I expect an adjustment of about $25 million to $28 million to calculate our full year pro forma adjusted EBITDAX if you are mid-point through that exercise to calculate a year-end leverage rate. And finally I will walk through an estimate of our liquidity at year end and all of this is assuming mid-points of guidance. Sources of capital are the bond offering which was $755 million of net proceeds, $40 million of common stock which we issued to Magnum Hunter, which by the way we filed the registration statement for those shares earlier this week, adjusted EBITDAX of about $330 million and cash at the balance sheet at the beginning of the year of about $80 million, uses of capital in 2013, our capital expenditure program of $475 million, financial cost of about $85 million, the tender offer and redemption of the tenants [3/8%] notes of 325 million, and the acquisition with purchase price adjustment of about $435 million. We would also expect about a $30 million favourable swing in working capital related to the capital program and some other non-cash add-backs. This scenario would have us overspending capital in 2013 by about $150 million which we would expect to finance on a revolver. We expect the borrowing base will be increased about $400 million in the fall redetermination up from what we expect in the spring redetermination of 320 to 350. So with the higher borrowing base, we would have about $250 million of liquidity at year end. And with that, Baird, that concludes the guidance review.

[Baird Whitehead:]

All right, thanks Steve. Ashley at this time, we are ready to go and take any questions.

[Operator:]

(Operator Instructions) Our first question is from Neal Dingmann of SunTrust. Your line is open.

[Neal Dingmann:]

Baird just wondered now going forward besides you are talking about depending on how you are going to do this wells and artificial lift, what your thoughts as far as -- we are not seeing some of your peers talking about doing some of this extended laterals and such, just kind of your thoughts on those, does the expense at this point make sense or what do you say right now on that?

[Baird Whitehead:]

Neal, you see as us drill long laterals on Lavaca county, geologically it’s a lot more quite. As we get up and to Gonzales County at least our legacy acres in Gonzales counties, there is a little bit more, (inaudible) up in Gonzales County which has restricted us as far as lateral lengths, but you guys see us routinely probably drill 6,000 to 7,000 foot laterals on Lavaca county on both are legacy acreage, the format we had and the Magnum Hunter acreage. Some of time Magnum Hunter wells, these recent Magnum Hunter wells are 7,000 to 8,000 feet lateral lengths Hunt who is the outside operator up in Gonzales County, they drilled up to 9,000 feet. As far as how effective incrementally the cost and benefit of doing that, we don't have our arms around it at this point. Theoretically the longer this lateral you should have higher reserves of course. I am not exactly convinced that always equates to higher IP rates, we are looking to spin a lot more time on that as we speak, but I think clearly it’s going to result in higher ultimate reserves.

[Neal Dingmann:]

Okay. And then just what do you see, you are thinking Baird, it sounds like down from five to four rigs, I mean certainly you are getting improving Eagle Ford results and now that you mentioned the financials are obviously much better shapes and you have extended that debt. Just your thoughts, I mean want to get your hands more and where you are in the Eagle Ford with the Magnum assets and all, will you decide at that time to ramp or is there certain kind of a metric that you guys look at, that you just don't want outstand cash flow to a certain degree because to me some of the results will justify it even going to five or back to even the six rigs, just want your thoughts about that, Baird?

[Baird Whitehead:]

It really is a short-term decision. We wanted to manage our spend, could there be case made depending upon ongoing improved results across the board where we consider ramping up, yes, but I mean we are committed to been able to self source, self fund our CapEx program here in the next two years or so, I mean I have made this commitment, I made it internally, I made it externally and it is our goal to follow through and make that work.

[Neal Dingmann:]

Okay. And then lastly if I could Baird, just wondered again, your kind of enthusiasm, it sounds like certainly that those Upper Eagle Ford zones, you know some of that potential could be very interesting; just kind of I guess any color you could add to that as far as across the play how that would work and just I guess how you are kind of thinking about that over the next 12 to 24 months?

[Baird Whitehead:]

Neal, we are convinced that there are actually separate reservoirs. It’s going to take well in each interval to exploit it. That would only emphasize further pad drilling. As far as how much of our acreage is up for Eagle Ford is perspective one, we are not crystal clear at this time. We are spending a lot of time mapping as we speak. As I said this Gonzales County well that we are drilling right now clarifies, I am not exactly sure how far that is, but if you look at our acreage map and if you look at the Fojtik well, really is almost one the far eastern part of our acreage which is the Fojtik well so almost the far western part of our acreage in Gonzales County. So it would be laterally, airily would give us some idea what we are talking about, but it doesn't exist across all of our acreage, but we think it exists across you know probably a swag would be maybe a third of our acreage at this time and we haven't talked about it. There was a case we made that selectively we might be able to drill up in the Austin Chalk; we've had some good shows in the Chalk itself that would make sense probably for us to go back in and look at it some point in time. So there is a third interval or at least across again some smaller part of our acreage position, but we are finding there's a lot of ways to do in general, I guess what I'm trying to say.

[Operator:]

Our next question is from Kim Pacanovsky of MLV & Company. Your line is open

[Kim Pacanovsky:]

Could you just let us know how many Magnum employees you brought on after the acquisition and going through their wells versus your wells, obviously a lot of the higher rate wells were some of their longer lateral wells. Are you seeing other differences besides the lateral links that has been responsible for those higher rates?

[Baird Whitehead:]

John, why don’t you take that question?

[John Brooks:]

Okay. At this point, the biggest factor does appear to be the lateral link. There is an added benefit with using the ESPs in the early life of the well to accelerate some recovery in the first six months of those wells and then they converge back to a fairly uniform type curve. So at this point from what we can understand the lateral link seems to be the biggest indicator.

[Kim Pacanovsky:]

Okay. And what is the additional cost of employing the ESP?

[John Brooks:]

On the capital side, the ESP installation is going to run between 300,000 and 400,000 and then there will be an incremental LOE component to power that for roughly a year of its early life in the well and before it goes to either rod pump or a gas lift, artificial lift method.

[Kim Pacanovsky:]

Okay. And then the first part of my question, were any Magnum employees brought over?

[John Brooks:]

We are in the process of extending offers right now. I think we've had one accept and we’re valuating a second one and hope to make an offer, but a lot of Magnum employees are going to stay with Magnum and a lot of the work we're finding out was done by contract employees and consultants. So there is not a huge pool Magnum Hunter employees for us to draw on; but we as all set and done, I think it's probably going to be a well over small number that we bring on board.

[Kim Pacanovsky:]

Okay, great. And then just one last question, any more thoughts on the midstream, your midstream, Magnum’s, Eureka midstream, how you might get some efficiencies there?

[Baird Whitehead:]

Kim, we have not gone through that at this time. I mean we are as far as whether we can join it together, we have a high pressure and low pressure system, they only have a low pressure system. There could be some sense to try to get those low pressure systems tie together at some point in time. But for right now we are going to continue to operate it as two separate systems.

[Operator:]

Thank you. Our next question is from Welles Fitzpatrick of Johnson. Your line is open.

[Welles Fitzpatrick:]

On the 70 acre spacing that you mentioned in the press release, is that 500 foot lateral spacing on 65,000 to 7,000 foot laterals or I guess if you could break it down or just tell us the separation of the lateral?

[Baird Whitehead:]

You got it. I mean if you just draw a rectangle, using about 500 feet between laterals and calculate the area. Those lateral that you mentioned would be about right to 70 acre spacing; I mean that’s why it's going to go up and down depending upon lateral length, people sometimes talk about I think different spacing in different ways, in calculating in different ways, but lateral length itself has a big bearing on the spacing calculation.

[Welles Fitzpatrick:]

Okay. So would that also imply then that up in Gonzales where you are going to be doing the shorter laterals spacing would be somewhere between 50 and 70 or am I just jumping ahead on that?

[Baird Whitehead:]

You are right in general Gonzales County legacy acreage they would have fewer laterals, so by definition using the same 450 to 500 feet spacing, they would have a shallower spacing that’s correct.

[Welles Fitzpatrick:]

Okay. Perfect. And did I hear you right that the new the upper Eagle Ford zone is about 100 feet above the lower one and if so have you guys look at micro seismic and do you know what the vertical frac height on those lower zone completions?

[Baird Whitehead:]

We have not, it is about a 100, it's 100 feet plus. As far as we have not done any microseismic work, we have plans to do so. We don't think that we are fracking from the lower Eagle Ford into this upper Eagle Ford at this time, and we would expect if we are fracking the upper Eagle Ford, that we would not frac down into the lower Eagle Ford. So it's going to take some confirmation of well test results and this microseismic in order to firmly determine that. But at this time we think they are probably separate reservoirs.

[Operator:]

Thank you again. Our next question is from Ray Deacon of Brean Capital. Your line is open.

[Ray Deacon:]

I had a question about the 30-day rates on the down space wells. Today do you have enough data to be able to say whether those compare to the 675 or so that you have been see on wider spacing?

[Baird Whitehead:]

John, can you answer to that question?

[John Brooks:]

Sure, the down space wells specifically I guess will be the Arkoma’s one, two, and three that we have the most data on. They float for a few days and then we shut them in for an offset frac. So I don't think we’ve got continuous 30 day rate on that, we just put those back on production about two weeks ago. We don’t have the 30 day rate, but from what we are seeing so far, the rates are holding up.

[Ray Deacon:]

I guess one other follow up, on the [pref.] rates question, if any of that goes away does it impede your ability to drill long laterals at all, or it is not going to matter too much?

[Baird Whitehead:]

Right, it will not matter at all.

[Ray Deacon:]

Okay, got it, and just last question in terms of M&A priority, I mean is it Granite Wash that you try to sell first or possibly the JV and the Eagle Ford again or I guess what you try to sell first?

[Baird Whitehead:]

As far as the Granite scheme, I think there will probably a case be made that we ought to consider selling our Eagle Ford gathering assets whether they are just our legacy assets which is both a gathering line and a gas lift line that could have further uses in oil transportation and oil gathering system. Whether we try to get it tied together with Magnum Hunter first and then sell it, but we are looking into getting some outside help and trying to figure out the best way to perceive. But I would say that would be at the top of the list, since we get the credit for it anyway in the market. I’d say second of which if we decided to sell anything, it would probably be gassier, probably would not include Granite Wash I am not going to say, I am not going to eliminate that option but it will probably something gassier like our [chalked] assets for instance. So that will probably be a 2015 event whereas we get our borrowing based up to the $400 million as Steve mentioned and then sell something on the reserve side so net-net our reserves would still be up year-over-year and give us sufficient liquidity to move ahead. So that's where our thinking is right now Rick.

[Operator:]

(Operator Instructions) Our next question is from David (inaudible) Howard Weil.

[Unidentified Analyst:]

I want to follow up on the upper zone of the Eagle Ford. I mean it sounds like the next well is kind of an acreage delineation well. At what point in your plans for this year would you then kind of do the upper and lower together tests where maybe you are doing micro seismic or trying to test you know the frac appearance between the two zones.

[John Brooks:]

Your question is to timing as to when we would test it and I would say the answer is right now. We've got a three well pad in Gonzales County that is about 17 miles southwest of the (inaudible) stick which was up first upper Eagle Ford test. We've got a three well pad where the middle well bore in the three will be an upper Eagle Ford test and the two laterals on either side of it will be a lower Eagle Ford test. So we are doing that right now.

[Unidentified Analyst:]

And then on the spacing I mean it looks like 70 acre spacing looks very good, are you guys planning to drill tighter wells or do another pilot program to test the tighter spacing.

[Baird Whitehead:]

I'd say the 450 to 500 feet is something which we are comfortable with. If we are getting closer than that, we would get concerned. So I would say that 50 to 70 acre spacing depending upon lateral length will be in a fair way what we do going forward. The longer the lateral, the higher the spacing by calculation; the shorter the lateral, the smaller the spacing.

[Unidentified Analyst:]

Okay, got it and then one just last question on the Pearsall. Is there a plan this year to drill another Pearsall well down deeper or is that kind of taking a backseat to some of the other stuff you are doing?

[Baird Whitehead:]

Right now, it will probably be a 2014. We are just going to sit back and produce and saying see how it acts and make a decision late this year going in to ‘14 as far as what to do.

[Operator:]

Our final question is from Biju Perincheril of Jefferies. Your line is open.

[Biju Perincheril:]

Couple of questions on well cost and the CapEx. I think you mentioned, you are assuming lower cost in the second half. I was just wondering can you give us some numbers how much lower and besides pad drilling, what are some of the factors that’s driving the cost lower?

[Baird Whitehead:]

John why don’t you go through that please?

[John Brooks:]

The biggest factor is yes the overall softening of the pressure pumping market that we've seen. Based on some frac jobs that we performed here in the last month or so, we see our simulation cost going down between $1 million to $1.3 million per well before additional efficiencies, pad drilling or any of those other considerations, just due to the softening of the market. So we have a contract that rolls over in July. We are fracking two more wells under that existing contract as we speak. We have two more to do next month. And after that point, all the higher cost stimulation contract will expire and will be more closely turn to what the spot market is. We should be as I mentioned to $1 million to $1.3 million per well savings.

[Biju Perincheril:]

And are you renewing those contracts so let’s say the existing provider or are you going to go on spot basis?

[Steve Hartman:]

We put all of that business out to bid to 10 or 11 providers including our existing service provider. We reduced that to the top four and have been over the last six weeks, are using those top four bidders to get an evaluation of how they could perform and we will use that information along with the price to make the decision ultimately going forward.

[Biju Perincheril:]

Okay, great. And then going back to the Upper Eagle Ford, Baird you mentioned you sort of estimated maybe a third of your acreage perspectives, is that based on the sickness of that zone that you see or is there maybe a geologic barrier that exist on part of your acreage, that’s separates the upper and lower members?

[Baird Whitehead:]

Visually, what it looks like it just is -- profit develops within that transition zone at Upper Eagle Ford zone in the areas in which the -- some areas it extremely tight, some areas it has processes we have seen in our pilot holes and have obtained open whole logs through that internal. So there is not a lot of open hole log information out there to get real good subsurface mats build, but that's we are in a process of doing right now, but it’s really a proxy development issue, it’s why it works versus not working.

[Biju Perincheril:]

And then one last question on, on that three well pad in Gonzales where the middle well is going to be in the Upper Eagle Ford, can you talk about the distance between the laterals, so if the design so that you have sort of your standard spacing for the Lower Eagle Ford well and then you are putting an Upper Eagle Ford well in between or the spacing you are sort of the standard spacing for all three wells?

[Baird Whitehead:]

John can you answer that please?

[John Brooks:]

Yeah, each of those three laterals will be in plan view 700 feet apart.

[Biju Perincheril:]

Okay, and how does that -- and I think that that sort of your standard…

[John Brooks:]

No, that's actually a down spacing. We have initially started out in our legacy acreage drilling all of our Gonzales County wells on 1,000 to 1,200 foot spacing between laterals. This will actually be a down space and a test of an upper zone at the same time.

[Operator:]

We have one more final question from [Adam Light] of RBC Capital Markets.

[Unidentified Analyst:]

A couple of questions, could you clarify in your Lavaca acreage you have now reached geometry or surface issues that would go into the lateral length there, is that correct.

[Baird Whitehead:]

In most cases, primarily we control the lateral length is geological issues. We have large and we have typically larger drilling units in Lavaca County which allows us to drill the longer laterals and the leases are configured as such, but typically geology allows us to drill longer laterals on Lavaca County.

[Unidentified Analyst:]

I think so. And then, can you talk a little bit about the differences and completion on JV versus what you would do and have you had discussions with them on your techniques?

[Baird Whitehead:]

John why don't you take that please.

[John Brooks:]

We have not had those discussions with Hunt yet. We are in the process of getting all of our counterparts in Virginia and trucks with the county parts in Hunt to better understand that. It’s a little bit different geologic setting or they are drilling. It’s in Marcellus County somewhat -- there have been some parts. We have not had a full discussion with all the technical staff between the two companies yet to better understand that.

[Unidentified Analyst:]

I guess you pretty much handle this, but if the pref rates are exercised in this drilling network no impact on spending or activity plans or anything else, is that right?

[Baird Whitehead:]

This are reducing in CapEx because the well cost go down because now we have partners in those wells. As far as activity level on a gross well basis, it would have no impact there. That is correct.

[Unidentified Analyst:]

So what's the maximum working interest difference if all the pref rates are exercised?

[Baird Whitehead:]

Well, just to swag if you took the $79 over 400, that will give you somewhat of an idea as far as what the overall reduction in working interest would be.

[Operator:]

Thank you. I'm not showing any further questions in the queue. I would like to turn the call back over to management for any further remarks.

[Baird Whitehead:]

Thank you, Ashley. I think if you can see we are making a lot of progress as far as the company goes in the Eagle Ford in general. We are extremely busy right now. You can see how many wells they are waiting on completion that we had shown in the press release. We've got a couple frac crews running on and off as we speak. So we would expect the second quarter to be a good quarter for us. So I think as we look for that second quarter (inaudible) and look forward to having our phone call discussing what we are doing. So thank you very much.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone have a great day.