Ranger Oil Corp (ROCC) 2015 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation first-quarter 2015 earnings conference call.

(Operator Instructions)

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.

Karen, thank you very much. I'd like to thank you for joining us today for Penn Virginia's first-quarter 2015 conference call.

I'm joined today by members of our Management team, which include 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 statement section of the press release as well as the Form 10-Q, which were filed last night. 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 simultaneously as part of the presentation.

First slide, slide 2, we have made some significant accomplishments during this first quarter, some of which I'd 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 to climb. We reached record levels, again, in the first quarter and was 23% higher than the fourth quarter and 45% higher than the first quarter of 2014.

We were extremely busy on the completion side. For the first quarter, we worked through our inventory of uncompleted wells. As a result of the eight-rig drilling program, we had much in which we were active during much of the second half of last year, and as a result our production volume response has been strong.

With 23 wells completed over the past 12 months, we feel that we have 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 could 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 60% lower than 2014. Steve will get into some more detail concerning the CapEx program a little later on. And despite this decrease in CapEx year-over-year, we continue to guide towards total Company production increase of 10% to 21% for the year, with the 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 continuing 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 the release, we stimulated over 1,400 frac stages over the last two quarters, had almost 100% operational success rate. We have you achieved about a 25% cost reduction from early in the fourth quarter of 2014 and expect a 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 focus on drilling our highest return wells in this lower cost environment. Our liquidity at the end of the first quarter reflecting the revised borrowing base and 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, the 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're 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 a corresponding 30-day rate for the appropriate wells of a little over 800 barrels a day equivalent. The oil IP rate increased to 1,054 barrels per day from 832 barrels per day, while the 30-day oil rate increased from 618 to 684.

In addition, we continue to feel more confident over time of the potential 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. 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 4 gives a lot of detail concerning what we hope to get accomplished per 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 to 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 approximately $10 million can primarily be allocated 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 area, with nearly 20% returns: and the Gonzales, Peach Creek and Rock Creek areas, with returns 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 approximately 35%. One thing we wish to remind folks of this, is that our well costs in addition to drilling and completion costs include almost $500,000 for any related surface facilities that take care of processing and separating our oil and gas, for many flowback or produced water.

With that I'd like to go ahead and turn the call over to John Brooks to give you some more detail as far as our operations.

Thanks, Baird. I'm going to flip over to page 6, which starts the first-quarter 2015 operations summary.

We've maintained our significant core land position of approximately 103,000 net acres. It's a highly contiguous position that we substantially de-risked with the drill bit over the last five years. 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, that highly contiguous nature of the acreage also gives us operational advantages related to gathering of the oil, gas and produced water and 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 pro forma for the sale of Mississippi assets and 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-and-perf operations and coil tubing drill out.

We have performed at this 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 7,500 psi fluid ends on their mud pumps, yielding an additional 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 a 10% increase in overall average ROP. This greater footage drilled per day is one of the primary drivers reducing the drilling portion of our capital costs.

During the first quarter, we completed and turned to sales 30 Eagle Ford wells, significantly reducing the inventory of wells generated by our prior eight-rig program. Of these 30 wells, 19 were completed in the Upper Eagle Ford. We accomplished this with minimal operational issues or delays and concurrent with the focus on reducing average well costs, which have decreased by approximately 25% since early fourth quarter of 2014 with completion costs decreasing by approximately one-third and drilling costs decreasing by approximately 17%.

In addition to reduced service costs, we have 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 incorporates a 250-foot stage length versus our previous 225-foot stage length. We've also reduced the amount of proppant per stage by 25% from 400,000 pounds to 300,000 pounds. Using tighter lateral spacing allows us to achieve an optimal stimulated rock volume with slightly fewer stages and 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 the 30-days 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 a lateral space nominally 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 of these wells had initial wellhead pressures in excess of 5,000 psi after coil tubing drill out of the frac plugs.

Implementing choke management, we've taken a very conservative approach to flowing these wells back, starting at a 10/64 and slowly increasing the choke size up to 16/64. The Upper Eagle Ford wells behaved very differently from the Lower Eagle Ford wells. The oil and gas rates 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 pressures than the Lower Eagle Ford in the RBK pad.

With these elevated initial flowing pressures, more aggressive choke management may have yielded substantially higher IPs. But we believe this more conservative approach appears to be achieving the designed results of preserving reservoir energy, maintaining higher production rates longer, and reducing the early life decline rate. We're targeting an additional $400,000 per well cost reductions over the rest of the year.' We're extremely pleased, and with the rapid improvement in our cost structure given the commodity price environment, our well returns remain attractive.

On 7 and 8 we graphically show these cost improvements, which are primarily on the completion and stimulation side but also with the significant improvement in drilling costs. Ours facility costs remained fairly constant, but as you can see and as I mentioned, we've 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 trip in the intermediate hole 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-source our guar and KCL substitute, and we continue to see improved competitive pricing on those two items, specifically, along with an overall decline in stimulation costs. Previously, we had discounted using trigger tow subs in favor tubing conveyed perforating with coil tubing, but improved engineering of some more recent trigger tow sub designs have strengthened their 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 at reducing total well costs.

On pages 9 and 10, we have summaries of IP data for our most recent Upper and Lower Eagle Ford well results, both of which continue to perform well across our acreage position. Results of these wells and the wells drilled over the past five years are used to generate what you see on the next three pages, which are the three 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 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.

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 curve. You will note the shallower decline that this play has demonstrated, and that is 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 upon earlier. These charts assume the additional $400,000 of cost savings are achieved in the type curves we just reviewed, along with a $65 oil and $3.50 price deck for gas. Assuming we continue to identify and high grade our drilling in these three areas, we feel very confident about achieving the returns shown on this page.

At this time, I'll turn it over to our CFO, Steve Hartman, for the financial portion of the call.

Okay. Thanks, John. Good morning. I'm continuing on the 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 were 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 is 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 two string wells in Gonzales County. We are also investing in Upper Eagle Ford model wells paired with the Lower Eagle Ford location. And we are finishing up the 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'll move on to the next slide an update our 2015 guidance. Total production guidance for the year is reaffirmed at 23,800 BOE 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 a range of 24,000 BOE 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 system 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 the 2014 CapEx program cost.

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 $255 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 the 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.

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't continue to increase it by continuing to take an income tax benefit against losses. Basically, how it works is we realize the income tax benefit and then it is immediately reserved 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 at $425 million, which is $25 million my 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 2016, the permitted leverage steps up to 5.25. Then, for 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 first quarter of 2017 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 remain 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 you amendment that says that we will not 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 in 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 slide. 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 $90.48. 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. That's about 70% to 80% of our oil production.

Some of these hedge versus a lower put, struck at $70 as shown on the slide, where we lose incremental hedge production 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 a $60 flat oil price, we would expect to receive $118.7 million in 2015 and $41.2 million in 2016. For our pricing assumption, we expect to receive $120.5 million in 2015 and that's included in our adjusted EBITDAX guidance. This should help you calibrate your models.

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 settlement.

That concludes the financial slides, Baird.

Thanks, Steve. Thanks, John. Karen, at this time I'd like to go ahead and open it up for any Q&A, please.

(Operator Instructions)

Our first question comes from the line of Welles Fitzpatrick from Johnson Rice.

Hey, good morning.

Hey, Welles.

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're seeing that's moving those up? Specifically, if that's a tweaking of the terminal rates or more IRR applicable near term rate?

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

Okay. That's great. 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?

Wild Hair. We have not filed the results of those -- there's an upper and a lower on the same pad. We have not filed the results of those wells yet.

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

Thanks, Welles.

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

Good morning.

Hey, Brian.

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

It drops somewhat -- it would drop somewhat. It actually takes us probably -- it would drop year over year. If you look at it on a quarterly basis, it would tend to flatten out going into 2016.

Okay.

That's probably the best way to answer that question.

Okay. So roughly it stays about flat then, from the second half production?

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

All right. Then, maybe just 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? Then, are you all finding any correlation of better well performance if you complete both at the same time, an upper and a lower?

Go ahead, John.

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

One other tidbit, Brian, just to add on to what John said. These four wells, unlike most of the wells we have drilled across our acreage, the laterals were drilled, actually, in the north/south direction. Whereas most of our laterals are drilled in a northwest/southeast direction. So these wells have done as well, if not better, than what we thought the directional preference would be on induced frac.

All I'm trying to say is. Lavaca County tends to, to some extent, prove that direction doesn't mean a lot as far as well results and will help probably develop better our overall lease position because not all leases are created equal as far as configurations go. If that makes sense?

That's good. 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?

Yes, I think it's at least two-thirds. 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. As we get some additional wells drilled this year, we certainly will get those sweet spots identified, like we have sweet spots identified for the Lower. It is productive, at least across two-thirds of our acreage, if not more, but yet to be determined exactly where all the sweet spots appear to be in the Upper.

I can 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.

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

All right, thanks, Brian.

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

Thanks. Good morning.

Good morning.

If I could ask a question on -- I think you all addressed this on reducing the proppant load into these wells. 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. Previously, it looks like you're using somewhere between 1,500 to 2,000 pounds. You're seeing better results with less proppant. It goes against what we're seeing elsewhere. Do you have any opinion or color on this?

Go ahead, John.

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 use quite a bit more hydraulic horsepower. If I had to guess at it or speculate, I would think we were probably getting a lot more frac length with those higher treatment rates in sand volumes, instead of the complex geometries that you hope to achieve in an unconventional play. To achieve, basically, more of a shattered glass approach to the shale than a long transverse fracture that's just simply parallel to the well bore. I don't know if that answers your question. 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 for where the treatment should be.

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

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

Okay. Fair enough. When you look at lateral lengths going forward, should we think about the 6,000 plus range as where you guys are looking at? Because you're focusing a little bit more on Gonzales where your highest returns are. Do those tend to be longer or shorter laterals?

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

Okay. So 5,500, 6,000, somewhere around there. Okay. All right. 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 -- 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 always on the table. Can you give us a little bit of a discussion on what you're thinking as you move into 2016?

Scott, this is Steve. Yes, 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 they just unanimously passed. 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 it's asset sales. It's JV partnerships. It's the various capital markets, debt, equity-linked equity, all the usual things that we would be looking at. 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 open to us.

Appreciate that. Thanks, guys.

Thanks, Scott.

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

Good morning, guys.

Hey, Neal.

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 2016, where you plan on running most of those? Or is that just going to be all over?

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 the returns are so much higher. But that in combination with the Upper Eagle Ford and identifying and excluding those sweet spots in the upper that we have taken care of or find so far, would probably be the basis of most of our program going forward into 2016.

A bit different -- I was looking back at that, I think it's in December when you had all four down 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?

That is correct.

Okay. 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?

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, as evidenced by the improvement in the 30-day rates. So preserving that energy is real important, especially in the higher GOR areas.

Got it. 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 cost, 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 capacity has increased?

They have. Costs have come down. On the completion side, though, probably 50% of our cost reduction is due to pricing, the other 50% is design optimization. That improvement's split between how we designed the wells and then how the market's pricing the goods and services.

Got it. Thank you all.

All right. Thanks, Neal.

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

Hey, Richard.

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 second half 2015 production?

I'd say probably $325 million to $350 million, someplace in that ballpark.

Okay. Similar to the budget this year?

Yes.

Okay. Looking at some of the recent wells, where you had the roughly 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?

I'm not exactly sure what the answer to that question is.

Okay.

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

Okay. That's fine. 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?

No, not yet. It's a little early. We'd have to wait and see what the banks come out with their price decks in the fall. I wouldn't expect it to go up, but I don't know where it will be from there.

Okay.

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

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

Thanks, Richard.

Thank you.

(Operator Instructions)

Our next question comes from the line of Sean Sneeden from Oppenheimer.

Hi, good morning. Thanks for taking the questions.

No problem.

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

Well, it would be required if we decided to do some kind of equity offering. As Steve mentioned earlier, we want to keep all of our 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 needed two-thirds. So we'll reconvene our annual meeting tomorrow and see if we get the vote. But that's the answer, best way I can answer that question at this time.

Sure. 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?

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

Fair enough. Maybe in terms of M&A, I guess a lot of folks have been thinking about second half of this year potentially picking up. You how are you guys thinking about that at this point, either participating or anything along those lines? I'm sure you guys have solved the metrics from the Rosetta deal. Is that something you guys, from a valuation standpoint, find attractive at all?

I haven't studied 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 approached us, we certainly would listen and consider doing something, but at this time our best strategy, we think, is to figure out how we're 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.

I think that makes sense. Maybe just lastly, maybe for you, Steve. How are you guys thinking about potentially layering hedging for 2016, just given the run up in the strip? Have we 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?

When we're looking at our hedging program, we're pre predominantly looking at 2016 since we're fully hedged for 2015. I'd say when the market has been touching $65, it's 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 collars.

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

All right. Thanks, John.

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

Thanks. Good morning, everyone. Most of my questions have been asked and answered. Just a couple maybe for Steve. The zero tax rate, should we also assume that, at least for now, for 2016 for modeling purposes?

For 2016, yes, I would just leave it going forward until we let you know otherwise.

All right. Then just one other question. I was disconnected for a couple minutes. I don't know if this was touched on. What was the backlog of uncompleted wells either at the end of Q1 or currently, if you have that?

I think we had around 30 uncompleted wells going into the first quarter, if I'm not mistaken, Steve.

Going into the first or going into the second?

Going into the first. Going into the second, John, help me out here.

Going into the second was 10.

Okay.

That's the average for the quarter.

Okay.

Then the average for fourth quarter was 21. That's completion inventory.

That's it. Thanks, everyone.

All right, Steve. Thank you.

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

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 -- ?

We're approaching it from the standpoint it's just better management of reservoir characteristics and reservoir energy. There could be some benefit from product pricing and the contango as far as oil prices going up over a period of time, but we're looking at it more so in the short-term management of reservoir pressure and energy versus something that may occur two or three years down the road. If that answers the question?

That's perfect. Also in terms of efficiencies that you guys talked about in cost down, and you were talk about maybe $65 as a possible hedging price. If we look at, say, we could get 6 million barrels of oil production, 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's no more cost downs. So I guess from my perspective, what do you think can drive EBITDAX margin to from the cost optimization side to bridge that?

You were sort of fading in and out, but I think what you're 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 -- do we think we can make further cost reductions on these wells? We do. We mentioned the $400,000 and I think we'll keep plugging along and find some ways to do things better over time, whereas we get the costs down, maybe another $0.5 million, no guarantees in trying to predict how much further we can get costs down. That in combination with a $65 or $70 oil price would have a fairly significant effect on returns on these wells. I think $65 to $70 is probably the fair way in which we want to layer in some additional hedges, whether they're swaps, or in all probability, try to put some collars in place that would give us some upside.

In terms of the comments that were made earlier, too, about 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?

Yes, almost everything we're doing --I don't want to say everything, but almost everything we're doing right now are multi-well pads and simultaneous fracking, i.e. zipper fracs.

Okay. Thanks.

All right. Thank you.

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

Hey, good morning. 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?

That would be on the cash flow statement. It's cash spent versus the capital program as accrued.

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?

I think it will probably smooth out, because in the first quarter, of course, we were paying a lot of the bills that we incurred in the fourth quarter, so I think a lot of that working capital adjustment has already worked itself into the numbers.

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

No, I think if you look at the revolver guidance that we gave and try to just line up your working capital, I think that's probably the best way to do it.

Right. Got it. On that, so even if there's not a borrowing base reduction your liquidity's 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 2016 I'm sure pricing will be another cash burn, so not super tight yet, but it certainly could be higher.

I can't say there is an exact minimum liquidity number that we are targeting. It's going to all be in context with oil pricing and what's going on with the whole Company in the market. As of right now, for 2015, we're looking forward to the year end, we think we're in good shape. As I pointed out in my remarks, we're very front-end loaded on the capital program, so for the second half of the year we're pretty much spending within cash flow. I think that's where we're focusing our attention right now, and we'll see how things are going toward the end of the year.

Okay. Super.

Just wanted to add one other thing. We always have the ability to adjust activity further, if need be, but at this point in time we do not have plans to do that.

All right. With that, Karen, I guess that's it for all the questions, correct?

Yes, sir.

All right. Anyway, just to conclude, we remain confident with what we're doing. We have improved our operational execution significantly since the middle of last year. Some of the issues that we reported in quarters past, we think are behind us as evidenced by the high success rate we're having on the completion side. We're going to do everything we can to keep our costs down and reduce them further. We think that's the most important thing we can do. And we're not going to stop. The reduction of costs, continuing to maximize our investment returns and managing liquidity, all go hand in hand, of course.

With that, look forward to our next quarter call and giving you some updates as far as what's going on with the Company new. Thank you very much.

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.