Penn Virginia Corporation
Q1 2015 Earnings Call Transcript

Published: 12 May 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation First Quarter 2015 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. As a reminder, this conference is being recorded. I would now like to hand the conference over to Baird Whitehead, President and Chief Executive Officer. Please go ahead.

[Baird Whitehead:]

Karen, thank you very much. And I’d like to thank you for joining us today for Penn Virginia's first quarter 2015 conference call. I am joined today by members of our management team, which includes John Brooks, our Chief Operating Officer; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; and Jim Dean, our Vice President of Corporate Development. Prior to getting started, I’d like to remind you of the language in our forward-looking statements section of the press releases, as well as the Form 10-Q, which were filed last night. And as was the case in the last quarter we are using a slide presentation, which is out there on our website, that we will go through simultaneous as part of the presentation. First slide, slide two, we have made some significant accomplishments during this first quarter, some of which I would like to highlight. Overall, production in the quarter was 16% higher than the fourth quarter, was 29% higher than the first quarter of 2014, which excludes any divested production. Our Eagle Ford production continues decline, we reached record levels again in the first quarter. It was 23% higher than the fourth quarter and 45% higher than the first quarter of 2014. We were extremely busy on the completion side of the first quarter. We work through our inventory of uncompleted wells. As a result of the eight rig drilling program, we had much, which we were active, doing much of the second half of last year and as a result, our volume response, production volume response has been strong. With 23 wells completed over the past 12 moths, we feel that we are successfully de-risked the Upper Eagle Ford across much of our acreage and have achieved excellent average results. Based on all the flowback and production indicators we have, our confidence level continues to increase that the Upper and Lower Eagle Ford are acting as separate reservoirs that we think can be developed separately or probably more appropriate in a lot of cases offset and stacked, and developed simultaneously from the same pad. Our 2015 CapEx program is now almost 6% lower than 2014. Steve will get into some more detail concerning the CapEx program a later on. And despite this decrease in CapEx year-over-year, we continue to guide towards total company production increase of 10% to 12% for the year, with a larger increase occurring during the first quarter of this year, with relatively flat production during the final three quarters of 2015. As I stated in the press release, while continue to increase production, our primary focus has been on cutting well costs and improving our operational execution. This has been extremely important to the company and John Brooks will highlight and demonstrate how our execution has much improved. As pointed out in a release, we stimulated over 1,400 frac stages over last two quarters at almost 100% operational success rate. We have achieved about a 25% cost reduction from the early in the fourth quarter of 2014 and expect to further $400,000 per well reduction beginning almost immediately. Also our unit operating expenses including direct, gathering processing and transportation and production taxes have all decreased. In addition, direct expenses are expected to decrease further based on some recent steps we have taken, especially in East Texas. Despite the recent improvement in oil prices we continue to be focused on maintaining healthy levels of financial liquidity and simultaneously focused on drilling our highest return wells in this lower cost environment. Our liquidity at the end of the first quarter reflecting the revised warrant based and the first quarter spending was $265 million. Steve will give some additional details concerning our borrowing base and revised covenants a little later on. Next slide, our production for the first quarter was 24,700 barrels a day equivalent of which 21,400 barrels equivalent was from the Eagle Ford by itself. Again, as I stated previously, our Eagle Ford production was up 23% from the fourth quarter and 45% up from the first quarter of 2014. Including the benefit of our strong hedge position, first quarter product revenues were $111 million or almost $50 per barrel equivalent. We are also making progress, as I stated earlier, in reducing our production costs, which includes direct gathering, processing and transportation and production taxes, which decreased by 7% or $0.84 per barrel equivalent to $10.68 per barrel equivalent quarter-over-quarter. The IP rates for the Eagle Ford wells completed since the fourth quarter averaged 1,288 barrels a day equivalent, with the corresponding 30-day rate for the appropriate wells of little over 800 barrels a day equivalent. The well IP rate increased to 1054 barrels per day from 832 barrels per day, while the 30-day well rate increased from $618 to $684. In addition, we continue to feel more confident overtime of the potentially of the Upper Eagle Ford across much of our acreage. Over the last 23 Upper Eagle Ford wells drilled and completed, the average IP and 30-day rates were 1,223 and 942 barrels equivalent per day. And I just want to point out the 942 if you compare it to the 30-day rates of all of our Eagle Ford wells, which was 809. It just confirms that these wells, the initial decline rates are flatter on the Upper Eagle Ford and clean up over a longer period of time. Slide four gives a lot of detail concerning what we hope to get accomplished for our strategy in 2015. Most important is to preserve our financial liquidity, which was $265 million at the end of the first quarter and remain within our leverage covenants, which have been substantially relaxed through 2017. It is important for us to manage our high spend for the year and the focus on cost control and drilling activity and related spending will be the single most important action we can take to manage this high spend. We have further reduced our lease acquisition budget considerably from last year when we spent almost $100 million. At this time lease spending will be held to a minimum and approximate $10 million, and primarily be allocated some -- to some key leases we want to acquire based on recent well results. In spite of the 56% reduction in CapEx year-over-year, we still expect pro forma production growth of 17% to 29%. We will invest our CapEx dollars in our highest return development areas, which include our Upper Eagle Ford with almost mid-teen returns expected based on a flat $65 per barrel oil price and $3.50 gas price. The Shiner Beer Quad with nearly 20% returns and the Gonzales Peach Creek and Rock Creek areas with returns of just over 30% due to the lower drilling and completion costs and higher oil content. As I stated earlier, we expect further cost reductions of about $400,000, under which scenario the Upper Eagle Ford and Shiner Beer Quad returns would increase to almost 20% and our Gonzales returns would increase to approximate 35%. One thing, we wish to remind folks of this, is that our well cost, in addition to drilling and completion cost, include almost $500,000 for any related surface facilities to take care of processing and separating our oil and gas for many flowback or produced water. And with that, I’ll like to go here and turn the call over to John Brooks, to give you some more details as far as our operation.

[John Brooks:]

Thanks, Baird. I’m going to flip over to page six which starts the first quarter 2015 operational summary. We maintained our significant core land position of approximately 103,000 net acres. It’s a highly contiguous position that we substantially derisked with drill bit over the last five years. And with our ongoing success in the Upper Eagle Ford and given our reduced pace of drilling activity, we have an ample drilling inventory in both the upper and lower Eagle Ford, which allows us to high grade our drilling program and optimize returns Also they are highly contiguous nature of the acreage also gives us operational advantages related to the gathering of the oil gas and produced water in flowback water. As Baird mentioned, we grew our total Eagle Ford production by 45% year-over-year and 23% sequentially. While overall production increased 29% year-over-year performer from sale of Mississippi assets of 16% sequentially. We continue to have operational success across our asset base in both the upper Eagle Ford as well as the lower Eagle Ford. In the first quarter, we pumped 832 stages, with an almost 100% success rate with the plug-n-perf operations and coil tubing drill out. We’ve performed the high operational execution level now for both the fourth quarter of 2014 and the first quarter of 2015. We also averaged in excess of five stages per day during pad stimulation operations. As you can see from the charts on the right side of the slide, we made significant progress in reducing well costs and operating expenses. All of our drilling rigs have now been retrofitted with 7500 PSI fluid ends on their mud pumps, yielding an additionally 800 psi of hydraulic advantage, which allows for further rate of penetration enhancement. This is reflected in our average footage per day growing from 902 feet per day to 988 feet per day which is about 10% increase in overall average ROP. And this greater footage drilled per day is one of the primary drivers we’re producing the drilling portion of our capital cost. During the first quarter, we completed and turned to sales 30 Eagle Ford wells, significantly reducing the inventory of wells generated by our prior acreage program. Of these 30 wells, 19 were completed in the upper Eagle Ford. And we accomplished this with minimal operational issues or delays, and concurrent with a focus on reducing average well cost which are decreased by approximately 25% since early fourth quarter ‘14 with completion cost decreasing by approximately one-third in drilling costs, decreasing by approximately 17%. In addition to reduced service cost, we've altered and optimized the design of our wells. On the drilling side, we’ve redesigned the wells to minimize the setting depths of surface casing and intermediate casing. Also in our three-string wells, we’ve not only significantly reduced our intermediate casing but we've also transitioned to using water-based mud in the intermediate section. We started a pilot program of this earlier back in 2014 and are now seeing the benefits of being further along that learning curve. On the completion side, our optimized stimulation design now incorporated 250-foot stage link versus our previous 225-foot stage link. We’ve also reduced the amount of proppant per stage by 25% from 400,000 pounds to 300,000 pounds. And using tighter lateral spacing allows us to achieve an optimal stimulated rock volume with slightly fewer stages, less proppant mass at lower cost while maintaining excellent well performance. We have preliminary data from these recent wells, in which we have pumped less proppant whereas the initial potential along with a 30-day rates are similar to those in which larger volumes of proppant were pumped. A good example of this and how well this completion design is working can be seen on our RBK pad. The RBK pad has four wells with a staggered offset lateral placement in both the upper and lower Eagle Ford with lateral spaced normally 400 feet apart in plan view and stimulation designed around our current design parameters of 250 foot stages targeting 300,000 pounds of proppant per stage. All these wells had initially wellhead pressures in excess of 5000 PSI air after coiled tubing drill out of the frac plugs. Implementing choke management, we've taken a very conservative approach to flowing these wells back starting at 1,060 force and slowly increasing the choke size up to 1,660 force. The upper Eagle Ford wells behaved very differently from the lower Eagle Ford wells. The oil and gas rate steadily increased concurrent with a more prolonged dewatering period for the upper Eagle Ford wells. While the lower Eagle Ford wells reached peak oil and gas production more quickly with less load-water recovery. The upper Eagle Ford wells also have a higher gas oil ratios and higher pressure in the lower Eagle Ford in the RBK pad. These elevated initial flowing pressures, more aggressive choke management may have yielded substantially higher IPs but we believe this more conservative approach peers to be achieving the desired results of preserving reservoir energy, maintaining higher production rates longer in reducing the early life decline rate. We’re targeting an additional $400,000 per well cost reductions over the rest of the year. But we are extremely pleased and with the rapid improvement in our cost structure, given the commodity price environment, our well returns remain attractive. On seven and eight, we graphically show these cost improvements which are primarily on the completion and stimulation side but also with a significant improvement growing cost. Our facility cost remained fairly constant. But as you can see and as I mentioned, we have identified approximately another $400,000 per well in additional savings during 2015. Continued improvements in reducing the number of days on location will drive additional drilling savings not only in rate of penetration but also in minimizing non-drilling time or flat time such as eliminating a wider tip in the intermediate whole section, changing our wellhead equipment to reduce rig time after we cement production casing, as well as continued improvements in pricing on casing and rentals. On the stimulation side, we self sourced our guar and KCL substitute. We continue to see improved competitive pricing on those two items specifically along with an overall decline in stimulation costs. Previously, we had discovered using trigger tows subs in favor of tubing conveyed perforating with coil tubing. But improved engineering of some more recent trigger tow sub designs has strengthened the value proposition. So we plan to reinitiate using trigger tow subs in the second half of the year. Continued coil tubing efficiency gains and further price reductions on other non-stimulation completion rentals and services will also be key to continued efforts of reducing total well cost. On pages 9 and 10, we have summaries of IP data for most recent upper and lower Eagle Ford well results, both of which continued to perform well across our acreage position. Results of these wells and the wells drilled over the past five years are used to generating what you see over the next three pages, which are the type curves that we are currently using. On page 11 is our Gonzales County type curve per frac stage, which is where we have drilled 46 wells over the past two years. The purple cloud you see in the background is the actual range of well results. The yellow squares are the average monthly rates of these well histories and the red line is our type curve projection, which as you can see is a very good fit as we try to make our projections match our history. On page 12, it's the Shiner Beer Quad type curve. We have drilled 38 wells in this vicinity over the past two years and we will essentially complete our Lower Eagle Ford development drilling program in this area over the next few quarters although the Upper Eagle Ford remains a promising target for this area. In the last type curve page on page 13 is our Upper Eagle Ford type curve. We have drilled 23 wells over the past 12 months, which form the basis of this type of curve. You will note that the shallower decline that this play has demonstrated and that was one of the primary reasons we're very excited about our Upper Eagle Ford play. Lastly and certainly of great importance are the rates of return in each of these areas, which Baird touched on earlier. This charge assumes the additional $400,000 of cost savings are achieved in the type curves we just reviewed, along with the $65 oil to $350 price deck for gas. Assuming, we continue to identify in high-grade, our drilling in these three areas, we feel very confident about achieving a return as shown on this page. At this time, I'll turn it over to our CFO, Steve Hartman for the financial portion of the call.

[Steve Hartman:]

Okay. Thanks, John and good morning. Continuing on with the financial slides, starting with our updated 2015 capital allocation shown on slide 16. We are raising our capital guidance for 2015 to a range of $325 million to $370 million. This is a $25 million to $30 million increase over our initial guidance we gave in February. The primary driver for this increase is a $25 million carryover from the 2014 capital program, specifically when we are running eight drill rigs and three completion spreads in the fourth quarter. For our first quarter program, our wells have been coming in at our anticipated lower cost, which includes an average $2.5 million cost savings per well as John explained earlier. We also have a $15 million increase in our anticipated drilling and completion capital related to a slightly higher net well count in our overall program. These wells will be coming online at the end of the year, so there isn’t a 2015 volume impact. It's more of a benefit to 2016’s program. This increase was offset by a $5 million to $7 million decrease in facility, G&G and other costs and a $5 million to $9 million decrease in our land spending. This capital will be largely front-end loaded, with about 70% of the capital being spent in the first half of the year and about 30% of the capital being spent in the second half of the year. As you can see on the graph on the right, we are focusing 28% development dollars in our lowest cost highest return locations in Peach Creek and Rock Creek. These are the 2-string wells in Gonzales County. We are also investing in Upper Eagle Ford model wells paired with a Lower Eagle Ford location and we are finishing our development in our Lower Eagle Ford Beer Quad area. Production growth with this program, pro forma for the sale of our Mississippi assets in 2014 would be 17% to 29%. We will move onto the next slide and update our 2015 guidance. Total production guidance for the year is reaffirmed at 23,800 to 26,200 BOE per day. We changed our production mix slightly, which isn’t shown on this slide but is in the guidance table in the press release. We now expect slightly higher oil volume offset by slightly lower NGL volumes due to our emphasis on the Gonzales County well locations. Natural gas volumes are unchanged. For the second quarter, we expect total production to be relatively flat to slightly higher with the range of 24,000 to 26,000 BOE per day. Our lease operating expense guidance is unchanged from February. Our gathering, processing and transportation expense should be lower because we are delaying startup of the oil gathering systems to the fourth quarter. Remember that’s a non-cash flow impact, just a change in geography on the income statement between realized oil price and GPT expense. Our production and ad valorem tax guidance is unchanged as is G&A expense. Our DD&A expense estimate is slightly higher mostly due to 2014 CapEx program costs. Our adjusted EBITDAX guidance for 2015 is reaffirmed at $300 million to $340 million. Our WTI oil price estimate is $55 in the second quarter, $60.50 in the third quarter and $62 in the fourth quarter. We are estimating $75 million to $85 million in adjusted EBITDAX for the second quarter. Our capital expenditures for the year are $325 million to $370 million as I discussed. For the second quarter, we expect $96 million to $107 million that would imply $83 million to $115.5 million for the second half of the year. For our liquidity, we expect $235 million to $265 million to be drawn on the credit facility at the end of the second quarter. Our borrowing base was reaffirmed at $425 million, which exceeds our previous guidance of $400 million. Including $2 million of letters of credit, our liquidity is expected to be $168 million to $188 million at the end of the quarter. With a lower capital program in the second half of the year, we expect most of our borrowing will be behind us and we will be spending close to within cash flow. We expect our credit facility balance to be $235 million to $275 million at year end. The one more thing I want to mention on guidance, starting in the first quarter of this year, our effective tax rate was reset at essentially 0%. We expect this to continue for the remainder of 2015. It’s fairly technical to explain but we had to set up a valuation allowance, which is like a reserve against our deferred tax asset on the balance sheet. The asset didn't go away but we can continue to increase it by continuing to take an income tax benefit against losses. Basically, how it works is we realized the income tax benefit and then it is immediately reserve against the asset and the benefit goes away on the income statement. So please just be sure to set your effective tax rate for us at 0% in your models going forward. On the next slide, we summarized the terms of our spring redetermination and amendment of our credit facility. As I mentioned, we redetermined our borrowing base of $425 million, which is $25 million higher than we anticipated. We also restructured and loosened our total debt leverage covenant. For the second quarter of 2015 through the first quarter of 2016, our permitted leverage will be 4.75. For the second quarter of ’16, the permitted leverage steps up to 5.25, then through the remainder of 2016, the permitted leverage goes up to 5.5. We will likely refinance the credit facility by year-end 2016. But in case we don't, the permitted leverage then steps back down to 4.5 for the first quarter ‘17 and then 4.0 thereafter. Our total debt leverage at the end of the first quarter was 3.5. Taking the midpoint of guidance, we would expect our leverage at year end to be around 4.2. So you can see this amendment gives us quite a bit of breathing room if oil prices remained low. We also now have a senior secured debt leverage covenant set at 2.75. At the end of the first quarter that ratio would have been calculated at 0.5 if it had been in place. We also have a provision in the amendment that says that we will now be allowed to pay cash dividends on the Series A and Series B convertible preferred if our total leverage exceeds 5.0. In that scenario, we would be required to pay the dividends and common stock. On the right side of the page, you saw this last quarter it’s just a reminder that we have no upcoming debt maturities. Moving on to the final side, we discuss our hedges. We have about 75% to 85% of our remaining 2015 production hedged as follows; 13,000 barrels of oil per day is hedged for second quarter at a weighted average floor price of $98.48, that’s about 85% to 90% of our total oil production. We have 11,000 barrels of oil per day hedged for the third and fourth quarters at a weighted average price of $89.86, and that’s about 70% to 80% of our oil production. Some of these hedges have a lower put struck at $70 as shown on the slide where we lose incremental hedge protection below that price, but we still receive protection between $70 and the weighted average floor price. We have 4,000 barrels of oil per day hedged for 2016 at a weighted average swap price of $88.12 and there are no lower puts in 2016. The graph on the right shows the cash we would expect to receive at various oil prices. At $60 flat oil price, we would expect to receive a $118.7 million in 2015 and $41.2 million in '16. For our pricing assumption, we expect to receive a $120.5 million in 2015 and that’s included in our adjusted EBITDAX guidance. This will help you calibrate your models. So the hedges are performing as designed. We received $37.5 million in the first quarter, which includes the December through February hedge settlements paid in the first quarter. We received $13.1 million in April related to the March oil settlement and we received $11.2 million in May related to the April oil settlements. And that concludes the financial slides.

[Baird Whitehead:]

Thanks, Steve. Thanks, John. And Karen at this time, I would like to head and open it up for any Q&A please.

[Operator:]

[Operator Instruction] Our first question comes from the line of Welles Fitzpatrick from Johnson Rice.

[Welles Fitzpatrick:]

Hey, good morning.

[Baird Whitehead:]

Hey, Welles.

[Welles Fitzpatrick:]

The Gonzales EURs seem to have jumped up a little bit to 563 from 520. I know you put, I think it's one extra stage on there. But could you maybe talk to what you are seeing that's moving those up? And specifically, if that's a tweaking of the terminal rates or more kind of IRR applicable near term rate?

[Baird Whitehead:]

We have not tweaked the terminal decline rates. They have remained consistent than anything we have shown. It’s just up-to-date information. We have drilled some very good wells in Gonzales County. One thing that we continue to see and it’s not unlike anybody experienced everybody else has, is you take some frac kits on some of these wells. And the Gonzales wells tend to rebound and actually improve in a lot of cases over and above what they were doing if we’re the frac it. So I would surmise that the increase in EUR is just because of updated information and performance issues, Welles.

[Welles Fitzpatrick:]

Okay. That's great. And then I apologize, I couldn't find the well on HPDI. I believe you guys were doing your first Eastern Lavaca well on the acquired acreage, what was the name of that one?

[Baird Whitehead:]

Well, here we have not filed the result of those. There is an upper and lower on the same pad. We have not filed the results to disclose yet.

[Welles Fitzpatrick:]

Okay. Perfect. Thanks. That’s all I have.

[Baird Whitehead:]

All right. Thanks, Welles.

[Operator:]

Thank you. And our next question comes from the line of Brian Corales from Howard Weil.

[Brian Corales:]

Good morning.

[Baird Whitehead:]

Hey, Brian.

[Brian Corales:]

I’ve got a couple questions. One, I mean, it does look like the second half of the year is largely around cash flows in term of cash flow and capital spend. If you keep those capital levels into 2016 kind of relatively flat, does that keep -- can production stay relatively flat at that level??

[Baird Whitehead:]

It drops somewhat, it would drop somewhat and actually takes us probably -- it would drop year-over-year. If you look at it on a quarter basis, it would tend to flatten out going into '16.

[Brian Corales:]

Okay.

[Baird Whitehead:]

It’s probably the best way to answer that question.

[Brian Corales:]

So roughly it stays above flat then from the second half production?

[Baird Whitehead:]

Yes. I mean, we tend to decline of course with the reduction in activity as the year progresses and with that activity level progressing into 2016, production would remain fairly flat yes

[Brian Corales:]

All right. And then maybe switching tunes. That RBK pad, I think John talked about, was that your first stacked Upper Eagle Ford and Lower Eagle Ford on a pad? And then, are you all finding any correlation of better well performance if you complete both at the same time, an upper and a lower?

[Baird Whitehead:]

Go ahead, John.

[John Brooks:]

Well, this is -- the RBK is the first time we’ve done four of these like this. We’ve got two up and two down. And I think we’ve got a lot of other paired laterals, but this is probably the best days that we’ve seen. What it looks like we are achieving is with the tighter well spacing and the way those laterals are placed is we can get a lot more bank for the buck with lower proppant load. So what we’ve seen that along with the choke management is that these wells have maintained their pressure very well. Couple this -- I think we’re probably very close to a calendar 30 days having at least two of those wells on production. And at that point, there were still have 3,000 PSI on the wellhead. So the production rates have remained strong. And if we were to take a more aggressive approach, we could have probably gotten a lot more eye popping IP, But it seemed like this was the more prudent course of action to maintain that production longer and achieve a lower decline rate.

[Baird Whitehead:]

And one other tidbit Brian just to add on to what John said, these four wells unlike most of the wells we had drilled across our acreage, the laterals were drilled actually in the north, south direction, whereas most of our laterals are drilled in the northeast and northwest southeast direction. So these wells have done as well if not better start the direction preference would be on induced track. So I am trying to say is as you go to Lavaca County it tends to some extend approve that direction doesn’t mean a lot of as far as well reserves and will help probably develop better our overall lease business because not all leases are created equal as far as configurations go.

[Brian Corales:]

No, that’s good. And one quick one if I may. I think in the past you talked about maybe two-thirds of your acreage having Upper Eagle Ford potential. These 23 wells or so that you all drilled, how much of that acreage have you all de-risked? Is it the majority of it, or do you think it's still two-thirds? Can you maybe elaborate there?

[Baird Whitehead:]

Yeah. I think you said least two-thirds. I mean, we’re still feeling our way around on trying to identify the sweet spots in the Upper. We don’t have that clearly scoped out at this point in time. But as we get some additional wells drilled this year, we certainly will get those sweet spots identified like we have sweet spots to identify for the Lower. So it is productive. It leads to across two-thirds of our acreage if not more. But yet to be determine exactly where all the sweet spots appear to be in the Upper. I can’t say that typically, as you go west to east, it appears the Upper because of the pressure, tends to get somewhat better. The better wells we have drilled in the Upper tend to be in Lavaca County.

[Brian Corales:]

All right, guys. Thank you. That was helpful.

[Baird Whitehead:]

All right. Thanks, Brian.

[Operator:]

Thank you. And our next question comes from the line of Scott Hanold from RBC Capital Markets.

[Scott Hanold:]

Excuse me. Thanks. Good morning.

[Baird Whitehead:]

Good morning.

[Scott Hanold:]

If I could ask a question on -- I think you all addressed this on reducing the proppant load into these wells. And when you look at it -- I think my numbers are about right, but you guys are currently thinking somewhere between 1,000 to 1,500 pounds per foot. And previously, it looks like you're using somewhere between 1,500 to 2,000 pounds. You're seeing better results with less proppant. It kind of goes against what we're seeing elsewhere. Do you have any opinion or color on this?

[Baird Whitehead:]

Go ahead, John.

[John Brooks:]

Well, I think what we've seen in the past is when we were achieving those higher proppant loadings that you mentioned; we were having to used quite a bit more hydraulic horsepower. And if I had to guess at it or speculate, I would think, we were probably getting a lot more frac linked with those higher treatment rates in same volumes, instead of the complex geometries that you hope to achieve in an unconventional play. To achieve basically I guess, more of a shattered glass approach to the shale than a long transverse facture that’s just simply parallel to the wellbore. So, I don’t know if that answers your question but I think that's the inference of what we've been able to see is that we can -- on the tighter spacing, the lesser amount of proppant seems to be where we’ve located the sweet spot is where the treatment should be.

[Scott Hanold:]

Okay. So basically, you're not communicating with the nearby wellbores as much as you were before effectively, is the benefit of doing the smaller proppant load? Is that right?

[Baird Whitehead:]

I think it's more of just the geometry of the stimulation. Stimulation has changed from having a long, a single frac plane to having the complex fracture geometries that breaks up the rock in the near wellbore region.

[Scott Hanold:]

Okay. Okay. Fair enough. And then when you look at lateral lengths going forward, should we think about the 6,000 plus range is where you guys are looking at, because you're focusing a little bit more on Gonzales where your highest returns are. I mean, do those tend to be longer or shorter laterals?

[Baird Whitehead:]

There is going to be some shorter laterals in Gonzales County but not a whole lot of them are going to be material shorter. And probably the shortest lateral, we would see would probably be around 4,500 foot or so. But there is also going to be some 7,000 proppants in there as well. So it's going be a mix.

[Scott Hanold:]

Okay. Okay. So 5,500, 6,000, somewhere around there. Okay. All right. And the last question I have is, when you look at your leverage, obviously, you've got enough cushion within your covenants as they were adjusted. When you step back and look at your overall leverage and where prices are right now and where that leverage goes to into 2016, what are the odds -- I mean, do you guys feel comfortable with that leverage moving into 2016? Are there ways you can improve that? Are you looking -- obviously, you've talked about asset sales before equity is always on the table. Can you give us a little bit of a discussion on what you're thinking as you move into 2016?

[Steve Hartman:]

Scott, this is Steve. Yeah, we’re very comfortable with the leverage where it’s at right now. The banks have been very supportive of us, as you can see from the amendment that they just unanimously passed. So, we’re in good shape with our leverage going into 2016. As I mentioned in my spoken remarks, 4.2 at year end. We still think is reasonably healthy compared to our peers. What could we do? It’s the usual things that we could look at and we’ll continue to look at anything that we need to during the year. But as asset sales, as JV partnerships, it’s the various capital markets, debt, equity-linked equity, all the usual things that we would be looking at. But as of right now, we think we're in pretty good shape and we just want to make sure that we have all of our options opened to us.

[Scott Hanold:]

Appreciate that. Thanks, guys.

[Baird Whitehead:]

Thanks, Scott.

[Operator:]

Thank you. And our next question comes from the line of Neal Dingmann from SunTrust.

[Neal Dingmann:]

Good morning, guys. Baird, or just for you, John, was wondering with the three rigs are you going to be focused -- could you just let me know for the rest of the year and times you enter ‘16, where you plan on running most of those or is that just going to be kind of all over?

[John Brooks:]

It will be all over, Neal. I’d say, you’re going to see us continue to tweak our program and try to do as many in Gonzales County as we can, because returns are so much higher, but that in combination with the Upper Eagle Ford and identifying and exploiting those sweet spots in the Upper that we have taken care of or find so far, we probably be the basis of the most of our program moving forward into ’16.

[Neal Dingmann:]

So a bit different, I was looking back at that, I think, it's in December, when you had all four down kind of in that very, call it, South, Central Shiner area, I guess, more of them now will be up towards, further North up towards the Peach Creek now given the new results you've been seeing?

[Baird Whitehead:]

That’s correct.

[Neal Dingmann:]

Okay. Okay. And then wondering, looking at those type curves that, John, went over. John, I guess, for you or again for Baird, just how -- the choke programs between Upper or the Lower, is there anything different you're doing there or is it just the nature of the wells why you're getting that much flatter decline when I'm looking at that Upper Eagle Ford type curve?

[John Brooks:]

Well, we are being a lot more conservative on our choke management, especially where we have the higher GORs. I think it makes a difference. It may not give the highest possible IP, but it does arrest the early life decline is evidenced by improvement in the 30-day rates. So preserving that energy is really important especially in the higher GOR areas.

[Neal Dingmann:]

Got it. And then, just lastly, I think, it was maybe even two quarters ago, I know just Baird on this call mentioned, the lower well cost that you're seeing or service costs, I should say? John, just wondering, I know, I think, it was two quarters ago when you had a bit higher sand costs, when you had to redo contracts and such, have some of those things either the sand or just the takeaway in general, some of those things costs come down just as this market has -- as capacity has increased?

[Baird Whitehead:]

They have -- the cost have come down. On completions side though, probably, 50% of our cost reduction is due to pricing, the other 50% is the design optimization. So that improvements kind of split between what -- how we design the wells and then how the markets pricing with the goods and services.

[Neal Dingmann:]

Got it. Thank you all.

[Baird Whitehead:]

All right. Thanks, Neal.

[Operator:]

Thank you. And our next question comes from the line of Richard Tullis from Capital One Securities.

[Baird Whitehead:]

Hey, Richard.

[Richard Tullis:]

Hey. Good morning, everyone. Thanks for taking my call. Baird just to verify, roughly what CapEx level in 2016, say drilling and completions budget could keep production relatively flat with the second half ‘15 production?

[Baird Whitehead:]

I’d say probably $325 to $350 someplace at that ballpark.

[Richard Tullis:]

Okay. Similar to the budget this year?

[Baird Whitehead:]

Yes.

[Richard Tullis:]

Okay. Looking at some of the recent wells, where you had the roughly 30, excuse me, 11% decline in 30-day rate on a BOE basis, but at the same time the oil rate kicked up about that same percentage level, 11% on a 30-day rate? What's the rate of return impact on that tradeoff there?

[Baird Whitehead:]

Well, I am not exactly sure what the answer to that question is.

[Richard Tullis:]

Okay.

[Baird Whitehead:]

Clearly the increase in oil is more of a benefit to decline in NLGs or any associated gas because of the relatively pricing. But I can't quantify the differential associated with increase in oil as far as it effect on rate of return, I don’t know what the answer is to that.

[Richard Tullis:]

Okay. That's fine. And lastly, this might be for Steve, any indications on what the borrowing base could move to at the next redetermination, say if oil stays current neighborhood of $60 a barrel?

[Steve Hartman:]

Not yet, it’s still a little early, we’d have to wait and see what the banks come out with their price deck in the fall. But I don’t -- I wouldn’t expect it go up, but I don’t know where it’ll be from there.

[Richard Tullis:]

Okay. Well…

[Steve Hartman:]

Just to give, put it in perspective, we came down 15% from the fall to spring and you know what prices did during that period. So hopefully there‘ll be some stability in that market.

[Richard Tullis:]

Okay. Well that's helpful. Thank you, Steve. That's all from me. Thanks.

[Baird Whitehead:]

All right. Thanks Richard.

[Operator:]

Thank you. [Operator Instructions] Our next question comes from the line of Sean Sneeden from Oppenheimer.

[Baird Whitehead:]

Hi, Sean.

[Sean Sneeden:]

Good mornings. Thanks for taking the questions.

[Baird Whitehead:]

No problem.

[Sean Sneeden:]

Baird, maybe for you, can you just maybe talk about a little bit on the pushback on increasing the share count and can you remind me, is that share count increase needed in order to issue equity or do a convert at this point?

[Baird Whitehead:]

Well, it would be required if we decided to do some kind of equity offering. I mean we -- as Steve mentioned earlier we want to keep other options open. The issue we had -- we didn’t have the requisite votes in order to get it passed. And there’s a fairly high threshold on order to get the share authorization approved, we need two thirds. So we will reconvene our annual meeting tomorrow and see if we get the vote. But that's the answer -- that's where I can answer that question at this time.

[Sean Sneeden:]

Sure. And I guess I don't know if you can provide this, but is there something that some of the -- we'll call them hold outs -- are looking for in terms of increasing the share count, or is there one item of pushback that they're saying? Can you give us a little color around that in terms of how are they thinking about not authorizing that?

[Baird Whitehead:]

We’ve already had conversation with shareholders and we’ve received their input. I can’t say there’s any single comment we received back. But we’ve made a significant efforts to talk to some of our shareholders over the recent week or so.

[Sean Sneeden:]

Fair enough. I guess maybe in terms of M&A, I guess, a lot of folks have been thinking about second half of this year potential picking up how are you guys kind of thinking about that at this point either participating or anything along those lines. I am sure you guys saw the metrics from, is that a deal is that something you guys from evaluation standpoint find attractive at all?

[Baird Whitehead:]

Well considering the -- I didn’t -- I haven’t stated the deal per se considering the premium received. I’d say it was attractive. What effect it may have on Penn Virginia, I have no idea. As we have stated in the past if somebody approach to us, we certainly would listen and consider doing something. But at this time our best strategy we think is to figure out how we are going to get through this current market and market conditions and product pricing conditions and continue to grow the company and build value that's day in, day out our most important objective at this point in time.

[Sean Sneeden:]

I think that makes sense. Maybe just kind of lastly, maybe for you, Steve. How are you guys kind of thinking about potentially layering hedging for 2016, just, kind of, given the run up in the strip? Have we kind of reached the point where the economics make sense to maybe layer in some collars or anything along those lines, or how are you guys approaching that?

[Baird Whitehead:]

When we are looking at our hedging program, we are predominantly looking at 2016. Its portfolio hedged for 15. I’d say when the market has been touching $65 its probably starting to look a little attractive. To your point, we can be locking in some reasonable returns at that level protecting cash flow. And so we’ve been considering that both swaps and callers.

[Sean Sneeden:]

Okay. That's helpful. Thank you very much.

[Baird Whitehead:]

All right. Thanks Sean.

[Operator:]

Thank you. And our next question comes from the line of Steve Berman from Canaccord.

[Baird Whitehead:]

Hi Steve.

[Steve Berman:]

Thanks. Good morning everyone. Most of my question have been asked and answered just a couple maybe for Steve. The zero tax rates should we also assume now or at least for now for 2016 for modeling purposes?

[Steve Hartman:]

For ‘16, yeah just I would just leave it going forward until we’ll let you know otherwise.

[Steve Berman:]

All right. And then just one other question, I was disconnected for a couple of minutes. And I don’t know if this was touched on but what was the backlog of fund completed wells either with the end of Q1 or currently if you have that?

[Baird Whitehead:]

I think we had around 30 uncompleted wells and going into the first quarter if I am not mistaken Steve.

[Steve Berman:]

Going into the first or going into the second?

[Baird Whitehead:]

Going into the first, going into the second, John, help me out here?

[John Brooks:]

Going into the second was 10.

[Baird Whitehead:]

Okay.

[John Brooks:]

And that's the average for the quarter, and then the average for fourth quarter was 21.

[Steve Berman:]

Got it, okay.

[John Brooks:]

That's completion.

[Steve Berman:]

All right. That's it. Thanks every one.

[Baird Whitehead:]

All right, Steve. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Phillip Pennell from Mariner.

[Phillip Pennell:]

Thanks for taking my question. In terms of the choke that Neal was talking about before. Obviously, you guys have said you're running a tighter choke on the Marl. How much of this is strategic? I think it's what you were getting at in terms of where prices are versus -- at $110 a barrel when you are in Gonzalez County, you turn on the fire hose. If you're looking at a steep contango in the forward market, what do you think about strategically trying to fit that into ….?

[Baird Whitehead:]

No. Sorry, we are approaching from the standpoint is just better management of reservoir characteristics and reservoir energy. There could be some benefits from product pricing and contango as far as oil prices are going up over 30 times. But we are looking at more or so in the short-term management reservoir pressure and energy versus Southern America or two to three years China road. If that answers your question.

[Phillip Pennell:]

Yes. That’s perfect. And I guess also in terms of efficiencies that you guys talked about in cost down. I mean -- and you were talking about maybe $65 as a possible hedging price. I mean if we look at, say, we could get 6 million barrels of oil production, I mean, still at $70, if you can only do 69% EBITDAX margin, you’re coming up a little short, obviously, on a breakeven for that $337.5 million let's say breakeven CapEx level. So $70 seems to me to be kind of where you would think about hedging, assuming that there is no more cost downs. So I guess from my perspective, what do you think you can drive EBITDAX margin to from the cost optimization side to kind of bridge that?

[Baird Whitehead:]

You were sort of saying in that, but I think what you are saying is $70 appears to be the better price to hedge at. I think it’s going to take a combination of hedges and further cost reductions because we think we can make -- do we think we can make further cost reductions on these wells? We do. I mean, we mentioned the 400,000. And I think we’ll keep plugging along if find some ways to do things better over time whereas we get the cost down, maybe another $0.5 million, no guarantees in trying to predict how much further we can gets cost down. But that in combination with the $65 or $75 oil price we will have a very significant effect on returns on this well. So, I think $65 to $70 is probably fair way, in which we want to layer in some additional hedges whether there is swaps or in all probability try to push some colors in place that will give us some upside.

[Phillip Pennell:]

In terms of the comments that were made earlier, too, about the frac geometry, you're referring to like the zipper frac that you guys have talked about in the past in terms of shorter laterals with better results?

[Baird Whitehead:]

Yes. Everything we’re doing almost everything we're doing, I won’t say everything, but almost everything we are going right now were multi-well pads and simultaneous fracking, i.e. zipper fracs.

[Phillip Pennell:]

Okay. Thanks.

[Baird Whitehead:]

Thank you.

[Operator:]

Thank you. Our final question for today comes from the line of Tom Nowak from Advent Capital.

[Tom Nowak:]

Hi. Good morning.

[Baird Whitehead:]

Hi, Tom.

[Tom Nowak:]

Just for 1Q, what's the difference between the $146 million CapEx you talked about in the tax in the guidance versus the actual $169 million number reported?

[Baird Whitehead:]

There will be on the cash flow statement, it’s cash spent versus the capital program that’s accrued.

[Tom Nowak:]

Okay. So put it another way, for the full year versus the $325 million to $369 million number you talk about, what should we expect in terms of an actual cash outflow?

[Baird Whitehead:]

I think it will probably smooth out, because in the first quarter, of course we were paying a lot of bills that we incurred in the fourth quarter. So I think a lot of that our working capital adjustment is already work that into the numbers.

[Tom Nowak:]

Mainly working capital, so it's not going to be a plus $20 million per quarter, basically?

[Baird Whitehead:]

No. I think if you look at the revolver guidance that we gave and try to just line up your working capital.

[Tom Nowak:]

Right.

[Baird Whitehead:]

I think that’s probably the best way to do it.

[Tom Nowak:]

Right. Got it. On that, so even if there is not a borrowing base reduction, your liquidity is going to be in the $150 million to $190 million range year end? Is there a minimum level of liquidity you want to keep? Because presumably in '16 I'm sure pricing will be another cash burn, so not super tight yet, but it certainly could be higher.

[Baird Whitehead:]

I can't say that there is an exact minimum liquidity number that we are targeting. It's going to be all in contacts with oil price, and what’s going on with the whole company and the market. But as of right now for 2015, we’re looking forward into the year end. We think that we are in good shape. And as I played out in my remarks, we are very front loaded on the capital programs. so for the second half of the year we are pretty much spending within cash flow. So I think that’s where we are focusing our attention right now and we will see how things are going towards the end of the year.

[Tom Nowak:]

Okay. Super.

[Steve Hartman:]

Tom, I just want to add one of the things. We have our ability to adjust activity further if maybe, but at this point time we do not have plans do that.

[Baird Whitehead:]

All right. With that, Ken, I guess I state all the questions correct.

[Operator:]

Yes sir.

[Baird Whitehead:]

All right. Anyway just to conclude, we remain confident with what we’re doing. I mean we have improved our operational execution significantly since the middle of last year. Some of the issues that we reported in the quarter past we think are behind this us is evidenced by the high success rate we’re having on the completion side. And we’re going to do everything we can to keep our cost down and reduce them further. We think that’s the most important thing we can do. And we are not going to stop. The reduction of cost continue to maximize our investment returns and managing liquidity, although hand in hand of course With that look forward to our next quarter call and give you some update as far what’s going on with the company new. Thank you very much.

[Operator:]

Thank you. Ladies and gentlemen, thank you for your participation in today’s conference. This does conclude the program and you may now disconnect. Everyone have a good day.