Ranger Oil Corp (ROCC) 2013 Q1 法說會逐字稿

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 listen-only mode. Later we'll conduct a question-and-answer session and instructions will be given at that time.

(Operator Instructions)

As a reminder, this call may be recorded. I would now like to introduce your host, Mr. Baird Whitehead, Chief Executive Officer. You may begin.

Ashley, thank you. Good morning. I would like to welcome to you Penn Virginia's first-quarter 2013 conference call. I'm 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 our Form 10-Q, which were 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 over time 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 an eight-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 exists 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-operated rigs drilling, but soon to be we'll reduce that to four operator rigs and two outside 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, 17.3 net of which will be on the Magnum Hunter acres that we acquired. Assuming an 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 in just oil, we expect to produce about 11,500 barrels of oil per day during the final nine months of this year versus 6700 barrels of 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.

Companywide, 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 affect of the ramp-up, the drilling, and the addition of the Magnum Hunter assets. Pro forma year-end 2012 crude reserves for the Company were about 126 million barrels, 30%, or 38 million barrels of which were in Eagle Ford alone. And as one would expect, we will experience ongoing growth in our proved oil reserves and will, therefore, benefit with increases in our boring base as the year progresses. Using the year-end 2012 pricing and pro forma proved reserves, our PB10 from the Eagle Ford shale alone was $844 million, $551 million of which was proved developed. With a significant probable and possible Eagle Ford inventory of roughly 530 gross and 345 net locations, the proved reserved value of the 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 from $400 million, which was our original intent, to $775 million. This upsizing also allowed us to repurchase the $300 million of 10.375% notes that matured in 2016, so we have, therefore, extended all of our note maturities out to 2019 and 2020 and going forward have saved about [$4 million] a year in annual interest payments. Pro forma 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 a little bit more detail on this in a few minutes.

As a cash flow from the growing oil production continues to increase and with an anticipated capital program going forward that is similar to or less than 2013, the out span and, therefore, our borrowings under the revolver are expected to continue to decrease as time goes on. In fact, our goal by late 2015 entering into 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 flows from operations, and our revolver of borrowings. And we're also considering some asset sales probably at the end 2013 or early in 2014 to further improve liquidity.

One thing I need to point out that we really have not talked about to date is in both Gonzales and Lavaca counties we have other working interest owners in our legacy Eagle Ford acreage. Our AMIs with those working interest owners require us to offer them with their proportionate interest of the Magnum Hunter assets. If all of our existing partners exercised preferential rights to purchase under those AMIs, our purchase price, or the $400 million, would be adjusted downward by about $70 million. This, of course, would results in an improvement in liquidity and we would end the year with slightly better credit issues -- credit statistics, excuse me. We should know the result of the prefer price issue by the end of this month or in early June, and it will be our plan once we know exactly what our final interests are we will put out some interim guidance to take that into account versus waiting until the second quarter.

The first quarter 2013 continued our positive trend to solid results achieving our seventh consecutive quarter of EBITDAX of $60 million or greater on 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 operation, we've had a number of positive developments which I will get into in some more detail. First of all, which is important for us, we have completely de-risked our Lavaca County acreage position which now includes Magnum Hunter acreage. We believe all of this acreage including the original 13,500 acre farm-out that we negotiated late in 2011, this perspective now for development drilling. Under the terms of the farm-out we now only have one well left to drill in order to earn all of the non-consent acreage associated with the original drilling units in Lavaca County. In addition, since the majority of this acreage has been HBPed, 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 farm-out has decided to participate in the second well in one of those original units in which they have a working interest. I think this is worth noting since there appeared to be a concern of the market, by the market, of why that partner in fact had left to go non-consent on any wells proposed after the first five. I think this only confirms that this was not necessarily the well results that caused that decision. Also mentioned in the press release were the details of 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 farm-out acreage. The Martinson well, which was one of those was drilled in the far Southeastern portion and tested almost 1900 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 Fojtik 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 drill laterally in a lower Eagle Ford interval, which is about 100 feet deeper, and is typically described by the industry as high redistibuty interval. The IP of this well assuming our typical type curve would match an approximately 500,000 barrel well, but we've only had this well on line for a little bit less than two months so we need, of course, some additional production information to confirm the reserves.

We also need to confirm that in fact it is completely 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're actually drilling a follow-up well in the same upper Eagle Ford zone in Gonzales County some distance away from this Fojtik well. If we can't 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 has already been HBPed.

One way we have figured out what the zone is, we drilled some pilot wells we've talked about in the past, ran some open hole logs. This upper Eagle Ford has always has some good mud logs shows as we've drilled through it. The open hole logs confirmed porosity, it's also a calcarius interval, easily fracked, it's sort of a transitional kind of zone between the Austin Chalk and the Eagle Ford. We're also continuing to add to our acreage position, Lavaca County addition to the original farm-out acreage and the Magnum Hunter Lavaca County assets. We have added within the last year or so about 2800 net acres and have another 4400 net acres in the hopper and we have been able to pick up much of this acreage from anywhere from $1000 to $1500 an acre. More over the results of the most recent wells drilled or 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 the 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 mention is the initiation of our down spacing, and we made reference to two paths that have been drilled in the first quarter and completed. One of which was a two-well pad, the other of 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 another three-well pad on approximate 70-acre spacing, and each of these wells right now are averaging about 1,000 barrels a day and about 400 Mcf a day. Going forward, since much of our legacy acreage is now HBPed, we will continue our development program more so with pad 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 completion costs and at a minimum we expect to reduce these completion costs 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 the results of our first Pearsall shale well. It test 992 Mcf a day and 140 barrels of oil a day and was recently turned in line. This clearly is less of a rate and gassier than what we had hoped, but we view this actually as a positive data point when we use this information to determine where we go from here. One option would be to go down dip where higher reservoir pressures and, therefore, higher production rates would be expected. And really, it would be similar to what we have seen in the Eagle Ford between Gonzales and Lavaca counties.

One other important finding that we find out is the gas and 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're going continue to gather production data with the intent to possibly drill another test well probably in 2014. So with that, I would like to turn it over to Steve so he can provide an update of our financial progress through the first quarter.

Okay. Thanks, Baird. And good morning, everyone. I'll start with the brief financial review of the first-quarter results. The first thing to note, our financial results in the first quarter do not include any of the effects of the Magnum Hunter Eagle Ford acquisition. That transaction closed on April 24th. So, all production, capital investment, cash flow impacts prior to that date are treated as a purchase price adjustment. You will you start to see results of the acquisition in our financial results in the second quarter.

Product revenues were $82.2 million, or $57.61 per barrel of 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 gas and NGL volume and 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 $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 derivative 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 costs related to the purchase of paraffin inhibitor needed because of the colder temperatures 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 50% of the extra expense.

We also had 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 sale last year. The remainder is due to costs 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 the higher expenses 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, not including any allocated G&A or hedges. Adjusted EBITDAX, a 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 effect 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 adjusts for the non-cash impact of hedging, gains on loss on sale, adjustments from income taxes or other adjustments disclosed on page 10 of the release, was $10.4 million or $0.19 per diluted share. 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 spent about $5 million on leasehold, primarily in Lavaca County.

Moving on to 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 of 2.5 times with trailing 12-month adjusted EBITDAX of $243.7 million. Pro forma for the acquisition debt was $1.075 billion. Cash was $5 million. Liquidity on the revolver was $275 million, which is our current borrowing base. We had nothing drawn on the revolver pro forma. The total liquidity of $280 million.

Pro forma trailing 12-month 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 the stay there. Our borrowing base is in the redetermination process right now. Wells Fargo, our lead bank, launched the redetermination with the bank group yesterday with a proposed borrowing base of $350 million. Wells Fargo received approval at their bank 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, but 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 hedge volume up prior to closing to 70% of anticipated volume for both oil and natural gas for 2013 and to about 35% in 2014. Once we closed the acquisition, we hedged another 2,000 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 with 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 a third for '14. We have achieved that now and we feel we're in a good position with our hedge portfolio.

Now 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 24th. Now remember that any financial activity prior to that closing date is treated as a 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 early 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 15th closing day.

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 costs for the Pearsall test that we took into this latest guidance. And this was partially offset by assuming lower completion costs 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 7.3 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 into account the strong results from wells we just brought on-line 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'm using as a proxy for our 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'd expect to receive about $13 million in cash proceeds from hedges. We're guiding higher for LOE for 2013. The primary cause 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're guiding toward the higher cost, but we should get a handle on these true go forward costs over the next quarter or two.

We're also adding some additional LOE money for corrosion and paraffin control in the Eagle Ford as I explained earlier, and adjusting for some higher R&M costs based on our experience in the first quarter. For adjusted EBITDAX, which includes cash receipts 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 of pro forma adjusted EBITDAX if you are going through that exercise to calculate a year-end leverage rate.

And finally, I'll walk through an estimate of our liquidity at year end. And all of this is assuming midpoints 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 a 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 $18 million. Uses of capital in 2013 are our capital expenditure program of $475 million, financial costs of about $85 million, the tender offer and redemption of the 10.375% notes of $325 million, and the acquisition with purchase price adjustment of about $435 million.

We also expect about a $30 million favorable swing in working capital related to the capital program and some other non-cash add backs. This scenario would have us over-spending capital in 2013 by about $150 million, which we would expect to finance on the revolver. We expect the borrowing base will be increased to about $400 million in the fall re-determination, up from the what we expect in the spring re-determination of $320 million to $350 million, 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.

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

Thank you.

(Operator Instructions)

Our first question is from Neal Dingmann of SunTrust.

Good morning, Baird. Great color today, guys. Say Baird, just wondered, going forward besides you were talking depending on how you are going do these wells and artificial lift, what's your thoughts as far as not seeing some of your peers talk about doing some of these extended laterals and such, just kind of your thoughts on those? Does the expense at this point make sense, or where do you sit right now on that?

Neal, you'll see us drill longer laterals in Lavaca County where geologically it's a lot more quiet. As we get up into Gonzales County, at least our legacy acres in Gonzales County, there's a little bit more fall complexity up in Gonzales County which has restricted us as far as lateral lengths, but you are going to see us routinely probably drill 6000- to 7000-foot laterals in Lavaca County on both our legacy acreage, the farm-out we had and the Magnum Hunter acreage.

They -- some of the Magnum Hunter wells, these recent Magnum Hunter wells are 7000 to 8000 feet lateral lengths. Hunt, who is the outside operator up in Gonzales County, they've drilled up to 9000 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 in time.

Theoretically, the longer these laterals you should have higher reserves, of course. I'm not exactly convinced that always equates to higher IP rates. We are looking or spending a lot more time on that as we speak. But I think clearly it is going to result in higher ultimate reserves.

Okay. And then just wanted to see your thinking, Baird. It sounds like going from five to four rigs, certainly you are getting improving Eagle Ford results and now that you are mentioning the financials are obviously in much better shape since you have extended that debt, just your thoughts?

Once you get your hands more around 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 to out spend cash flow to a certain degree? Because to me, certainly the results would justify even going to five or back to even six rigs. Just wondering your thoughts about that, Baird?

It really is a short-term decision. We wanted to manage that outspend, Neal. Could there be a case made depending upon on-going improved results across the board, would we consider ramping up? Yes. But we are committed to being able to self-source, self-fund our CapEx program here in the next two years or so. I've made this commitment. I've made it internally, I've made it external, and it is our goal to follow through and make that work.

Okay. And then lastly if I could, Baird, just wondering again your enthusiasm? It sounds like certainly that those upper Eagle Ford zones, some of that potential, could be very interesting, just any color you could add to that as far as across the play, how that would work, and just how you're thinking about that over the next 12 or 24 months?

Neal, if we're convinced that they're actually separate reservoirs, it is going to take well in each interval to exploit it. That would only emphasize further pad drilling. As far as how much, on how much of our acreage this upper Eagle Ford is prospective on, we're not crystal clear at this time.

We're spending a it lot of time mapping it as we speak. As I said, this Gonzales County well that we are drilling right now as the crow flies, I'm 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, to almost the far Western part of our acreage in Gonzales County. So, it would be laterally, aerially it would give us some idea of what we're talking about. But it doesn't exist across all of our acreage.

But we think it exists across probably a swag would be maybe a third of our acreage at this time. And we haven't talked about it, there's a case to be made that selectively we might be able to drill up in the Austin Chalk, too. We've had some good shows in the Chalk itself that would make sense probably for us to go back in and look at some point in time. So there's a third interval at least across, again, some smaller part of our acreage position. But we're finding there's a lot of things to do, in general, I guess, is what I'm trying to say.

great. Thanks, Baird. Look forward to all the activity.

All right. Thanks, Neal.

Our next question is from Kim Pacanovsky of MLV & Co.

Good morning. Lots of good news to talk about.

Hello, Kim.

Hello. Could you just let us know how many Magnum employees you brought on after the acquisition? And in 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 lengths that has been responsible for those higher rates?

John, why don't you take that question.

Okay. At this point, the biggest factor does appear to be the lateral length. 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 length seems to be the biggest indicator.

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

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

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

You know, we are in the process of extending offers right now. I think we've had one accept and we're evaluating 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's not a huge pool of Magnum Hunter employees for us to draw on, but when it's all said and done I think it's probably going to be a relatively small number that we bring on board.

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?

Kim, we have not gone through that at this time. We're -- as for as whether we can join the two 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 tied together at some point in time. But for right now, we're going to continue to operate it as two separate systems.

Okay. Terrific. Thanks so much.

You're welcome.

Our next question is from Welles Fitzpatrick of Johnson.

Good morning.

Hello, Welles.

On the seven-acre spacing that you mentioned in the press release, is that 500-foot lateral spacing on 6500- to 7000-foot laterals? Or, I guess if could you break it down or just tell us the separation of the laterals on there?

You got it. I mean, if you just draw a rectangle using about 500 feet between laterals and calculate the area, those lateral lengths that you mentioned would be about right to get 70-acre spacing. That's why it is going to go up and down depending upon lateral length. People sometimes talk about different spacings in different ways, and calculating different ways. But lateral length itself has a big bearing on the spacing calculation.

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

You're right. In general, our Gonzales County legacy acreage they would have shorter laterals so, by definition using the same 450 to 500 feet spacing, they would have a shallower spacing. That's correct.

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

We have not. It is about 100, it's 100 feet plus. As far as we have not done any micro seismic work. We have plans to do so. We don't think that we're 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 is going to take some confirmation of well test results and its microseismic in order to firmly determine that, but at this time, we think they are probably separate reservoirs.

Perfect. Thanks so much. That's all I have.

Thank you.

Our next question is from Ray Deacon of Brean Capital.

High, Ray.

Hello, good morning, Baird. How are you?

Great.

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

John, can you answer that question?

Well, sure. The down space wells, specifically, would be the Elk Hunters 1, 2, and 3 that we have the most data on. They flowed for a few days and then we shut them in for an offset frac, so I don't think we've got a continuous 30-day rate on that We just put those back on production about two weeks ago. So, we don't have the 30-day rates. But from what we've seen so far the rates are holding up.

Okay. Got it. And I guess just another follow-up on the pref rights question. If any of that goes away does it impede your ability to drill long laterals at all, or is it not going to matter too much?

It will not matter at all.

Okay. Got it.

It will happen there.

Okay. Got it. And just last question. In terms of M&A priority, is it Granite Wash that you would try to sell first, or possibly a JV in the Eagle Ford again, or, I guess what would you try to sell first?

As far as the grand scheme, I think there would probably be a case to be made that we ought to consider selling our Eagle Ford gathering assets. Whether they're just our legacy assets, which is both a gathering line and a gas lift line, it could have further uses in oil transportation, 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 on trying to figure out the best way to proceed.

But I would say that would be at the top of the list. Once we would get no 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 the Granite Wash. I'm not going to say -- I'm not going to eliminate that option, but it would probably be something gassier like our Chalk assets, for instance.

So, that would probably be a 2010 event where as we get our borrowing base up to the $400 million that Steve mentioned, and then sell something on a 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 what our thinking is right now, Ray.

Okay. Got it. Thank you.

You're welcome.

(Operator Instructions)

Our next question is from David Amoss of Howard Weil.

Good morning, guys.

Hello, David.

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

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

Your question is to -- timing as to when we would test it, and I would say the answer is right now. We have got a three-well pad in Gonzales County that is about 17 miles Southwest of the Fojtik, which was our 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're doing that right now.

Okay. Got it, thanks. And then on the spacing, 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?

I would say the 450 to 500 feet is something we feel comfortable with. If we get any 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 fairer way of what we do going forward. The longer the lateral, the longer -- or the higher the spacing by calculation. The shorter lateral, the smaller the spacing.

Okay. Got it. And then just one last question on the Pearsall Is there a plan this year to drill another Pearsall well down dip or is that taking a backseat to some of the other stuff you've done?

For right now it would probably be a 2014 event. We're just going to sit back and produce this thing and see how it acts and make a decision late this year going into '14 as far what to do.

Okay, got it, thanks.

You're welcome.

Our final question is from Biju Perincheril of Jeffreys.

Hello, good morning, Baird. A couple of questions. On well cost in the CapEx, I think you mentioned you were seeing lower costs 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 costs lower?

Why don't you go through that, please.

All right. The biggest factor is just the overall softening of the pressure pumping market that we've seen. Based on what we've already performed, some frac jobs that we've performed here in the last month or so, we see our stimulation costs going down between $1 million to $1.3 million per well before additional efficiencies of 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're 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 have expired, and we'll be more closely attuned to what the spot market is, which should be, as I mentioned, $1 million to $1.3 million per well savings.

And are you renewing those contracts with the existing provider or are you going to go on a spot basis?

We've 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 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.

Okay. Great. And then going back to the upper Eagle Ford. Baird, you mentioned you estimated maybe a third of your acreage prospectives. Is that based on the thickness of that zone that you see, or is there maybe a geologic barrier that exists on part of your acreage that separates the upper and lower members?

Biju, what it looks like, it's just the property develops within that transition zone, that upper Eagle Ford zone, in the areas in which it -- some areas it's extremely tight. Some areas it has porosities we have seen in our pilot holes and have any open hole logs through that interval. So, there's not a lot of open hole log information out there to get the real good subsurface maps built, but that's what we're in the process of doing right now, but it's really a porosity development issue is what works versus not working.

Got it. And then one last question. On the primo 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, is it designed so that you have your standard spacing for the lower Eagle Ford wells, and then you are putting an upper Eagle Ford well in between? Or be the spacing, you're using the standard spacing for all three wells?

John, go ahead and answer that please.

Yes, each of those three laterals will be in planned view 700 feet apart.

Okay. And how does that -- and I think that's sort of your standard --

No, that's actual down spacing. We initially started out in our legacy acreage drilling all of our Gonzales County wells on 1000- to 1200-foot spacing between laterals.

Got it.

So, this will actually be a down space and a test of an upper zone at the same time.

Got it. That's very helpful. Thank you.

Thank you, Biju.

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

Hello, Adam.

Good morning, guys. I had a little bit of phone problems but I think most of my stuff has been covered. Couple of questions. Could you clarify in your Lavaca acreage you have no lease geometry or surface issues that would limit the lateral length there, is that correct?

In most cases, primarily what controls the lateral length is geological issues. Where we have larger -- 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 in Lavaca County. Is that answering your question?

I think so.

Okay.

And then can you talk about the differences in completion on the Hunt JV versus what you would do, and have you had discussions with them on their techniques?

John, why don't you take that please.

Okay. We have not had those discussions with Hunt yet. We are in the process of getting all of our counterparts in Penn Virginia in touch with the counterparts at Hunt to better understand that. It's a little bit different geologic setting where they're drilling. It's in Gonzales County, it's somewhat up dip in some parts. So, we have not had a full discussion with all the technical staff between the two companies yet to better understand that.

Okay, that's great. Thank you. And then I guess you pretty much handled this, but if the pref rights are exercised, there's really no impact on spending or activity plans or anything else, is that right?

Well, there would be a reduction in CapEx because of well costs would go down because now we have partners in those wells. But as for as activity level on a gross well basis, it would have no impact there, that's correct.

What's the maximum working interest difference if all the pref rights are exercised?

Well, just to swag, if you took the $70 million over $400 million, that would give you some what of an idea as far as what the overall reduction in working interest would be.

Okay. Thanks. Appreciate that.

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.

All right, thank you, Ashley. I think you can see we're making a lot of progress as far as the Company goes, in the Eagle Ford in general. We're extremely busy right now. You can see how many wells that are waiting on completion that we had shown in the press release.

We've got a couple of frac crews running on and off as we speak, so we would expect a second quarter to be a good quarter for us. So, in any case, we look for that second quarter, our earnings release, and look forward to having our phone call discussing what we're doing. So, thank you very much.

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.