Penn Virginia's (PVA) CEO Baird Whitehead on Q2 2014 Results - Earnings Call Transcript

Aug. 1.14 | About: Penn Virginia (PVAHQ)

Penn Virginia Corporation (PVA) Q2 2014 Earnings Call July 31, 2014 10:00 AM ET

Executives

Baird Whitehead - President and CEO

John Brooks - COO

Nancy Snyder - CAO

Steve Hartman - CFO

Jim Dean - VP, Corporate Development

Analysts

Brian Corales - Howard Weil

Neal Dingmann - SunTrust

Welles Fitzpatrick - Johnson Rice

Gail Nicholson - KLR Group

Scott Hanold - RBC Capital Markets

David Tameron - Wells Fargo

Steve Berman - Canaccord

Kim Pacanovsky - Imperial Capital

Subhash Chandra - Jefferies

Richard Tullis - Capital One

Operator

Good day ladies and gentlemen, and welcome to the Penn Virginia Corporation Second Quarter 2014 Earnings Call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions). As a reminder, today's conference is being recorded.

I would now like to introduce your host for today's conference Mr. Baird Whitehead, President and CEO of Penn Virginia Corporation. Sir you may begin.

Baird Whitehead

All right. Thank you very much, Candace, and thank you all for joining us today for Penn Virginia second quarter 2014 conference call. I'm joined today by members of our management team, including 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, we would like to remind you the language in the forward-looking statements sections of the press releases issued yesterday as well as our Form 10-Q, which was filed last evening.

Let me begin by saying that overall we are pleased with our progress in the quarter as our cash flows and margins remained in line with our expectations. We recently completed some very important transactions as we released, and also we continue to drill some very good wells in the Eagle Ford.

We did face some timing issues at the end of the first quarter that extended into the second quarter, mostly relating to operational complexities associated with pad drilling and the completions on those pads, which caused production in the quarter to be below expectations. John Brooks is going to get into a little bit more detail about that and as important get into some of the corrective measures we have taken to expedite in streamline or drilling and completion program.

As we continue to improve our production by working through these operational challenges, I would like to point out we remain confident we will deliver significantly higher production levels in the second half of this year and into 2015 and beyond.

Our confidence is based on the fact that we continue to see the benefit of enhanced productivity associated with pad drilling and the quality and results of our drilling program has and we will continue to improve. The ITs, along with a 30-day rates for the wells completed and turned in line in this most recent quarter reflect the longer-term trend of improved ITs and 30-day rates of wells completed on pads.

This benefit, along with the addition of the two rigs in the second half of the year we pointed out in the press release, would drive our production increase later in the year and again into 2015.

Now moving on to some of the highlights for the quarter. Second quarter production from the Eagle Ford increased 6% to 15,618 barrels equivalent per day compared to 14,761 barrels of oil equivalent per day in the first quarter.

In the Upper Eagle Ford, we are particularly pleased with our early results. The Welhausen A2H well was turned in line in March of this year has averaged 1,070 barrels equivalent per day over the first 95 days; 1,519 barrels of oil equivalent per day over the first 60 days.

The Martinsen 2H well was turned in line in May of 2014 and is averaged to 1,149 barrels of oil equivalent per day over the first 60 days. Production from both of these wells is significantly above the early time performance of our Lower Eagle Ford tight curves used in these same areas.

There is a case to be made for each of these wells that the early time production information will support at a minimum barrels of oil equivalent in ultimate reserves, in fact there's a case for the Welhausen well to be close to 1.5 million barrels. The Welhausen well has already produced a little over 67,000 barrels and almost 400 million of gas or 134,000 barrels equivalent. Post processing, the queue to-date is a 168,000 barrels equivalent. So you can see how we're getting to the million barrel number pretty easily.

The Martinsen well has produced almost 50,000 barrels and 230 million cubic feet of gas or 88,000 barrels equivalent. Post processing, the queue to-date of this well is 100,000 barrels equivalent.

Currently I want to point out Welhausen well after almost four months is still producing over 350 barrels a day and 2.9 million a day preprocessing and the Martinsen well is producing 320 barrels a day and at the same rate 2.9 million a day. The bottom-line is both these wells are excellent wells.

We recently announced the acquisition of approximately 11,600 net acres for $45 million. We should close on this acquisition in August. This new acreage is an excellent feet with our current Shiner acreage in Lavaca County. With this acreage, this acquisition we are now at approximately 102,000 net acres into play exceeding the 100,000 acre minimum goal that we put into place at the beginning of the year. But let me emphasize that this was a minimum target. We are not done yet. We will continue to expand our position by primarily looking in our backyard with an ongoing leasing effort.

For 2014 lease acquisition guidance is now $97 million to $115 million for the year which includes the funds for the recently announced acquisition. Our leasing effort will slow down somewhat going forward, but this effort continues to grow value for per shareholders. As I have pointed out in the past, to illustrate the growth and value, if you buy an Eagle Ford acre for about $3,500, drill it with $9.2 million well, that acre after recovery of the investment is now worth anywhere from $73,000 per acre to $135,000 per acre depending upon the spacing. Again this shows how attractive the arbitrage is by continuing to acquire acreage in the Eagle Ford.

Since our last report, we acquired about 16,100 acres, including a recent acquisition at an average cost of about $3,700 per acre. We are well positioned in the play, are extremely confident of this high quality position that we currently have, and the potential for production and reserve growth in the play is substantial. We now have remaining drilling inventory the total is over 1600 locations, a 1000 of which are in the Lower Eagle Ford and 600 of which are in the Upper Eagle Ford. The total number of locations is about 8% greater than the 1,510 locations we told you about in the first quarter call.

This increase is driven by our ongoing leasing effort, along with our recent acquisition; along with new locations added due to the recent success in our Upper Eagle Ford program. It also should be pointed out this does not currently assume any potential overlapping inventory in the Upper Eagle Ford with both the upper and lower intervals would be both productive. There could be as many as 400 additional Upper Eagle Ford locations in our western Lavaca County acreage, but we plan to do is to drill some additional operative Eagle Ford wells on this acreage to further confirm that the upper and lower are separate reservoirs. We hope to have all these 400 potential locations confirmed by the end of this year or very early in 2015.

The two additional rigs I referenced earlier will be added soon and will enable us to accelerate Upper Eagle Ford development in the Welhausen area. We have eight Welhausen wells to drill, the first two of which we've already spud, and those eight wells would be drilled from four different pads. In addition, we will further increase our Upper Eagle Ford program and if were to test the potential of our western Lavaca County acreage.

With the recent excellent upper Eagle Ford results, we now think the potential in the Upper Eagle Ford for this company could be significant. We expect our efforts in the Upper Eagle Ford, along with the development program, in the Beer Quad area that we discussed in the past, will be important drivers of the increased production in the second half of this year and into 2015.

Looking ahead and taking into account modest increases in production during the first half of the year, along with an increase in drilling and a substantial ramp up in production during the second half of the year, we are adjusting our 2014 production guidance to range between about 8.8 million barrels equivalent and 9.2 million barrels equivalent.

Considering our first half production was 3.9 million barrels equivalent, our second half guidance is now approximately 5 million barrels to 5.3 million barrels. This implies growth in total 2014 production of 30% to 35% over 2013 and 54% to 62% growth in oil production alone. We have simultaneously increased our preliminary guidance for production for 2015, with approximately 45% growth in oil, and about 35% overall production. Steve will give you some more detail on our guidance in a few minutes.

Importantly, we have the necessary capital and our financial flexibility to implement our plans to drive increased production across our assets. As you saw in the press release yesterday we closed the sale of the rights to construct and operate an oil gathering and intermediate transportation system covering a portion of our Eagle Ford acreage for $115 million. This sale, together with a sale of gas gathering and gas-lit systems earlier in the year for $96 million, and expect to close of the sale of our Mississippi assets here in the next day or two for $73 million, brings our total proceeds to $319 million, which exceeds our goal that we put in front of everybody $300 million early in the year.

In addition we also received a very favorable outcome to the arbitration proceeding associated with last year's Eagle Ford acquisition of approximately $34 million. The sales of these non-core assets, along with our recent $325 million convertible preferred offering, and the $34 million arbitration settlement has significantly improved our balance sheet. With our strong balance sheet, and appreciable increase in EBITDAX driven by our increased production, we are now in a very comfortable position to fund the CapEx program not only for this year but plan for the remainder of next year also.

And at this time, I would like to turn the call over to John Brooks, so he can give you some additional operational detail for the second quarter.

John Brooks

Thank you, Baird, and good morning. A few of the operational highlights include production in the second quarter of 2014 was approximately 21,800 BOE per day compared to approximately 21,100 BOE per day in the first quarter. Second quarter Eagle Ford production increased 6% to approximately 15,600 barrels of oil equivalent per day compared to approximately 14,800 barrels of oil equivalent per day in the first quarter.

Our second quarter Eagle Ford production growth has been touched on was less than expected primarily in April and May, given delays in the timing of a number of completion, much of that do in no small part to dramatically increasing completion inventory that followed our ramp up and drilling activity.

In June 2014, our production was over 23,000 barrels of oil equivalent per day and in July 25, it was about 23,800 barrels of oil equivalent per day. So we believe we are well-positioned to beat our third quarter expectations.

With respect to our Eagle Ford operations, in June of 2014, our production was 16,800 barrels of oil equivalent per day and production was approximately 18,100 barrels of oil equivalent per day in July through July 25.

As Baird mentioned, and Steve will elaborate on, a significant jump in production is expected to take place during the fourth quarter, due to the fact that a large number of higher working interest wells from the new rigs are expected to be turned in line in October and November, while the third quarter is expected to show a modest increase over the second quarter. Year-to-date we have turned in line 43 gross, 28.2 net upper Eagle wells excluding two shallow wells.

We are increasing our rig count to eight in the second half of 2014 with the addition of a seventh rig in August and the eighth drilling rig estimated to commence drilling in September. As a result, we expect to turn in line 68 gross, 39 net wells during the remainder of 2014, for a total of 111 gross, 67 net operated wells to be turned in line during 2014, excluding the shallow wells.

Currently, in the Eagle Ford, we have 11 gross, 6.3 net wells completing, 11 gross, 5.0 net wells waiting on completion, and 6 gross, 4.6 net wells being drilled.

Since our last quarterly report and excluding two shallow wells, we have turned in line 25 gross, 15.2 net operated wells. These wells have an average IP of 1,514 barrels of oil equivalent per day over an average of 25.4 frac stages with 81% of the production coming from crude oil. Of these 25 wells, 15 had sufficient production history to provide a 30-day average rate of 948 barrels of oil equivalent per day, with 77% of production coming from crude oil. Among the recent wells, the wells with the highest IPs included the Bock number 7H, which IP is 3,175 barrels of oil equivalent per day, and it's a company record for us, over 26 frac stages. At the Cinco Ranch LTD Unit number 1H 2,611 barrels of oil equivalent per day over 32 frac stages. The Bock number 6H 2,272 barrels of oil equivalent per day over 26 frac stages. The Amber 1H 2,217 barrels of oil equivalent per day over 23 frac stages. The Amber 2H 1,919 barrels of oil equivalent per day over 22 frac stages, and the Wombat number 1H 1,670 barrels of oil equivalent per day over 20 frac stages.

Also notable was our first successful swap completion, in which we completed seven wells on three pads in one unit, mainly the Bock unit. This was the fourth unit in the Beer Quad and all seven wells came on line in the last week of June. These wells were all drilled in the Lower Eagle Ford on 400 foot lateral spacing and involved something a total of 183 stages averaging over 4,000 pounds of profit per stage. The sum of the IPs from the seven well unit exceed 12,000 of barrels of oil equivalent per day.

The strong performances of these recent wells give us confidence as we move into the second half of this year, and was attributable primarily to the location in the Beer Quad area near Shiner, the Peach Creek area, and the Rock Creek Ranch/Bozka areas.

Turning to the Upper Eagle Ford. It's suffice to say that early time well production is far exceeding expectations and it is increasingly evident to us that this is a separate reservoir from the Lower Eagle Ford at least in the areas we have tested thus far.

To-date, we have tested three Upper Eagle Ford Marl Shale wells, the Fojtik number 1H, the Welhausen A2H, and Martinsen number 2H. And for the remainder of 2014, we have 19 additional Upper Eagle Ford wells planned to spud, with eight of those scheduled as development wells in the Welhausen area and 11 planned to test in other areas all off of multi-well pads.

As Baird mentioned, based on early time data, the Welhausen and Martinsen wells each could have an EUR exceeding 1 million barrels of oil equivalent. As a result, we believe that the Upper Eagle Ford at least in these areas appears to be the more prolific reservoir and that is consistent with our belief that the Upper Eagle Ford thickens relative to the Lower Eagle Ford as you drill deeper to the east and southeast.

Expanding on Baird comments, we plan to spud eight development wells in the Welhausen area and 11 test wells in the western Lavaca County area, in order to gain understanding of how the Upper Eagle Ford works in locations, which have historically been core Lower Eagle Ford areas.

Currently in Eagle Ford, we have approximately 143,200 gross and 102,000 net acres, including the recently announced acquisition of 13,125 gross 11,660 net acres for $45 million.

As Baird mentioned, our aim is to continue expanding our Eagle Ford in the Eagle Ford. We have increased our undrilled location inventory from approximately 1,510 to approximately 1,635 locations. Over 600 of these locations are in the Upper Eagle Ford and the potential for another 400 Upper Eagle Ford locations overlying our Lower Eagle Ford in the western Lavaca County area, which we will test during 2014 and 2015.

I now want to speak towards some of the operational challenges that we have encountered of late. Operational challenges encountered on multi-well pads, are obviously magnified and sometimes multiplied by the well counts on the pad in question. In particularly had two four well pad and these occurred in the second quarter in Lavaca County on a Rock Creek Ranch, wide four well pad. All four wells were programmed to TD at the respective lateral length and yield a total of 139 stages for fracking.

While drilling, we encountered geologic faulting near the toe of the laterals that resulted in loss circulation. This in turn led to shorter effect laterals. So instead of completing the originally planned 139 stages, we were only able to treat 125, which is a 10% reduction.

Another example occurred in Gonzales County, in Peach Creek, in the Wombat 100 unit. As you are probably aware, our Peach Creek wells largely in Gonzales County are two string wells, while in Shiner in Lavaca County higher pressures require the third casing string. The pressure transition however, is not as simply demarcated as the county line. All four Wombat wells were drilled down bit toward Lavaca County. Before reaching TD on the first well, we encountered this pressure transition out in the lateral, which resulted in a sidetrack and subsequently shorter laterals for all four wells.

So what was originally programmed for 117 stages on these four wells resulted in only 83 stages, a 29% reduction in compellable stages, further complicated by the delay associated with the sidetrack. These two examples occurred in Gonzales County and affected a total of eight wells in the quarter. The collective measures we have taken include reprocessing our 3D Seismic data to better image geologic faulting in subsurface complexities. Additionally, identifying this pressure transition in the northern regions of Peach Creek to help us avoid similar situations going forward.

In Lavaca County, the challenges were more mechanical in nature. Historically, we have set 4.5 inch casing as our third casing string. Working in 4.5 inch casing at high temperatures and pressures presents challenges in drilling, completion, and production. On the drilling side, the smaller tools used in the 4.5 inch casing, well designed, require NWD and directional tools that have a meaningfully shorter life downhole, further compensated by the higher temperatures we see in Lavaca County, especially in the Beer Quad.

On the completion side, the 4.5 inch casing requires more horsepower and results in a lower maximum treating pressure. As we have ramped up our screen volume this lower maximum treating pressure constraint has frequently resulted in premature screen-outs. This in turn often requires a cold given cleanout in the middle of the frac job, which can result in additional cost delays and importantly not getting out of profit place. Before a half inch casing, also had a higher incident rate of mechanical difficulties and plug-and-perf operations, which also causes delays, additional cost and sometimes loss stages.

In the second quarter, four of our Shiner wells on two pads experienced these challenges, resulting in material delays in what was originally planned for 133 stages among these four wells, resulted in only 94 stages, once again a 29% reduction. The primary collective measure we have instituted here is to upsize the well bore in our three string wells with a goal of having 5.5 inch casings as our production casing. We've also installed led coolers in our hot hole areas that cool the drilling mud before accompany down hole which yields longer tool life and ultimately greater effective rate of penetration.

The larger 5.5 inch casing should result in lower horsepower requirement, higher allowable treating pressures, more effective sand placement, and les mechanical risk in the plug-and-perf operations. We will be putting heavier steel in the ground. So while our drilling tangible costs will rise somewhat all indication so far is that this changing well design results in an overall lower well cost with higher mechanical success.

Moving onto those well costs, our average well cost was $9.4 million during the second quarter, down from the approximate $10.2 million average well cost during the first quarter, even with the aforementioned operational challenges. On a per stage basis the average total well cost per stage decreased from about 410,000 per stage in the first quarter to about 370,000 per stage in the second quarter. Our stimulation costs had been running about 120,000 to 135,000 per stage as we continue to ramp up total sand volumes to roughly 1,800 pounds of profit per lateral foot.

In addition the amount of profit per stage increased from an average of 308,000 pounds in the first quarter to an average of 367,000 pounds in the second quarter. We are currently in the negotiations for the next 12-month stimulation services with multiple service providers. These contracts are expected to be one-year contracts and we are confident that the cost increases will not be substantial from what we've seen so for. We continue our other cost reducing our efficiency enhancing initiatives, including the use of spudder rigs to preset surface casing, optimizing walking rigs to backset intermediate casing on the preset surface casing, and then drilling in casing at laterals without having to lay down and pickup drill pipe repeatedly. On our three stream wells this saves us on average an estimated $140,000 and over $100 per well.

For the first half of 2014 utilizing these and several other integrations, we have increased our effective footage drill per day by 12% compared to 2013.

As mentioned we have also reduced our cost by providing our own drilling fluids and fluid engineering services on our drilling rigs. On average, running our own mud and in effect buying mud products wholesale, saves us a minimum of about $100,000 per well often more.

That concludes my operational update and at this time I will turn it over to our CFO, Steve Hartman.

Steve Hartman

Okay. Thanks John and good morning. I'll start with a summary of our second quarter financial results as compared to our first quarter results.

Product revenues for the quarter were $136.4 million, 2% higher than the previous quarter. Revenues from oil and natural gas liquid sales were $120.1 million, which is 5% higher than the previous quarter. The primary driver is our higher volumes and higher realized oil prices, offset by lower realized natural gas and NGL prices.

Direct operating expenses, excluding share-based compensation expenses, were $36.4 million or $18.36 per BOE, compared to $30.6 million or $16.08 per BOE in the previous quarter.

Lease operating expenses were higher due to a variety of items; some higher water disposal costs; chemical costs; and fuel lubricate costs as examples. This was also the first full quarter of operating under our new gas gathering agreement so that impacted LOE and gathering expense by about $1 million over the first quarter.

G&A was higher primarily due to $1.1 million of non-recurring expenses related to our recent accounting system installation which is now complete, non-core asset sale expenses and arbitration related expenses.

Adjusted EBITDAX, which includes the cash impact of derivatives, was $95 million in the second quarter, and $189 million for the first half of the year.

Operating income was $26.3 million for the quarter, excluding $117.9 million impairment related to the sale of our Mississippi assets. This was $11.4 million higher than the $14.9 million reported in the first quarter excluding a gain on sale related to the Eagle Ford gas gathering system sale. The improvement in operating income was driven by higher product revenues, lower exploration expense, lower DD&A expense, and lower share-based compensation expenses, offset by higher direct operating expenses.

Capital expenditures for the quarter were $170 million, compared to $182 million in the first quarter. Drilling and completion capital was higher at $154 million, compared to $135 million in the first quarter. As John mentioned we have higher than anticipated inventory wells waiting on completion at the end of the first quarter. We caught up a lot of backlog with 25 wells turned in line during the second quarter, compared to 16 wells turned in line during the first quarter.

Leasehold acquisition expenses or expenditures were $24 million lower in the second quarter at $13 million. Pipeline facilities and other expenditures were also lower this quarter at $3 million, compared to $10 million in the first quarter.

Moving on to capital resources and liquidity. As previously announced we issued $325 million of Series B convertible preferred stock during the quarter. The net proceeds were used to pay down debt and ultimately will be used to fund the acceleration of the drilling program through 2015. Concurred with the issuance of the Series B preferred stock, we have converted about 23% of the Series A depository shares in the 5.9 million shares of common stock. We paid $3.4 million in inducement payments during the second quarter and an additional $900,000 since the end of the quarter as part of the conversion.

At quarter-end, we had $55 million outstanding on our credit facility, and $25 million of cash on hand. Our borrowing base at quarter-end was $475 million. Our liquidity under the borrowing base at quarter-end was $443 million including letters of credit.

Upon closing the Mississippi sale, we will take $37.5 million reduction in our borrowing base but we expect to more than make that up in the fall borrowing base redetermination.

Our leverage at quarter-end was 3.1 times total debt to pro forma adjusted EBITDAX, compared to 3.6 times at the end of the first quarter, and well below our credit facility covenant of 4.5 times.

Pro forma adjusted EBITDAX at quarter-end for the trailing 12-months period as defined in our credit agreement was $361 million compared to $353 million last quarter. Our second quarter adjusted EBITDAX annualized is $380 million and our leverage using that statistic is 3.0 times.

Since the end of the quarter we have announced the sale of our Mississippi assets for $73 million, before purchase price adjustments and fees. We also announced sale proceeds of $150 million related to the crude oil gathering system and the acquisition of leases in Lavaca County for cash at closing of $34 million, the other $11 million would be a carry that would start being paid in 2015.

Pro forma for these two sales and the one acquisition, our liquidity at quarter-end is approximately $630 million and our leverage is 2.6 times.

Now on to our guidance update, which is detailed on page 11 of the release. This update includes the effect of selling our Mississippi assets as of the end of July. We are increasing our 2014 capital expenditures guidance to a range of $762 million to $808 million, which implies second half 2014 capital expenditures of $410 million to $456 million.

The primary drivers for the increase are the addition of a seventh rig in August and the eight rig in September. Our lease acquisition guidance is also increased to allow for the recently announced acquisition in Lavaca County for $34 million and that's cash at closing. The remaining $12 million to $13 million of discretionary lease acquisition money would be used to continue to form drilling units and expand in our target areas as Baird described. With that remaining money we should be able to add about 4000 to 8000 net acres by the end of the year.

For 2014 production guidance we are adjusting our oil guidance lower by about 8% to a range of 5.3 million to 5.55 million barrels. This has partially offset by an increase to our NGL guidance and a tightening of our natural gas guidance. This shift in production mix is a result of increasing our development focus on the higher GOR Welhausen and Beer Quad type wells in the second half of 2014.

For total production we are reaffirming the bottom-end of our guidance range adjusted for 260,000 BOE or about 1,750 BOE per day of production from the divested Mississippi assets. Our new guidance range for total production is 8.8 million to 9.2 million BOE. At the midpoint in guidance we would expect 58% oil production growth in 2014 over 2013 and 32% growth in total production.

As we've been saying for the last several quarters, since we've started pad drilling we expect our production growth to remain lumpy, although we expect healthy oil growth in the third quarter, we expect the majority of our growth to occur in the fourth quarter, as we started to see production contributions from the seventh and eight rigs kick in.

Our production numbers for June and July, as John outlined, are on track with this type of growth.

We are lowering LOE guidance per BOE in response to higher anticipated volumes. We are also raising our G&A guidance slightly to allow for some modest additional staffing adds to support the two additional rigs.

For adjusted EBITDAX, we are reaffirming our previous guidance of $440 million to $485 million, or $251 million to $296 million in the second half. We assume $90 oil. So we think our conservative price assumption is going to offset the lower production from the first half of the year.

For our program funding, using the midpoints of guidance, we expect the 2014 capital program will be fully funded and still be able to pay down debt by about $200 million, which would leave our credit facility close to undrawn at the end of the year.

Our guidance or the credit facility balance right now is set at 0 to $65 million. Our leverage should end 2014 at about 2.4 times and we should have over $400 million in liquidity at year-end. This calculation assumes we will have received $34 million final settlement from Magnum Hunter that was decided on by the arbitrator two days ago on July 29.

Moving on to 2015, we are expecting to continue with the eight rig program for the full year. We estimate capital expenditures will be around $750 million to $800 million, with drilling and completion spending at $710 million to $750 million. Our oil production should be around 45% higher than 2014 and total production should be around 35% higher than 2014.

Adjusted EBITDAX should be about 35% to 40% higher and that's assuming $90 oil and $4.25 natural gas. From midpoint of 2014 guidance that would put our adjusted EBITDAX for 2015 at around $620 million to $640 million.

Our outspend should be around $250 million. So the $200 million surplus we should see in 2014 should come close to funding the 2015 outspend.

We would therefore expect to end 2015 with credit facility debt of around $250 million to $300 million.

Our leverage should be at the end of the year around 2.1 times to 2.2 times and our liquidity at the end of 2015 should remain at $300 million or better assuming we have receive borrowing based increases of about $50 million per redetermination which we have been seeing in the past.

And then looking forward further even with the addition of the seventh and eighth rigs we expect to be committed to fully funded with cash flows by 2017.

Baird that concludes financial results and guidance.

Baird Whitehead

Thank you, Steve. At this time Candace, we are ready to take any questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions).

Our first question comes from the line of Brian Corales at Howard Weil. Your line is open.

Brian Corales - Howard Weil

A couple of quick questions and maybe I will start with you Baird the Upper Eagle Ford, you have had some great results. How much of your current acreage position do you think is perspective one and then two, how much have you tested?

Baird Whitehead

As far as what we think is perspective especially with this recent acquisition we made which the merits of which were primarily based on the upper, I would say I had estimated this time probably around 60% to 70% of our acreage is perspective in the upper. A good rule of thumb is the Gonzales Lavaca County alone is probably a pretty decent line, a demarcation where we think the upper is perspective going east.

As far as what percent of our acre is we think we have tested so far, not only our wells and some third-party wells, I would add 70% if you take into account the acres on trend would be Martinsen and Welhausen and others a Schuster well and tarjack well memory serves me correct. I would say, I would guess probably half of our acreage we feel pretty good about.

One of our maps we had a blog on that we added the recent 600 locations and really that blog could be extended on acreage we just picked up. That we announced. So really we need to do is get a western Lavaca County acreage tested. But at this point in time based on large characteristics of whatever pilot wells we've may drilled throughout our overall development program at Eagle Ford and Holly openhole logs look and some of the shows we have as we are drilling through this stuff even drilling Lower Eagle Ford wells, I think we have all have a high degree of confidence that this is going to work out just great for us.

We are drilling some -- starting to drilling some pad Upper Eagle Ford wells. I think, in fact I know all the remaining 19 wells that we will spud before the end of the year are pad wells, most of those pads being two well pads. But we're going to start to develop in the Upper as we would typically develop the lower. So probably more than what you asked but we feel very good about the effort this time.

Brian Corales - Howard Weil

That was helpful. And I guess kind of went to another point I guess the 600 locations in the Upper Eagle Ford that doesn't include that was it 10,000 or 12,000 acres you just added, so that 600 is probably going to go higher without even testing your western Lavaca acreage?

Baird Whitehead

We actually threw I think 150 locations for the upper on the acres we acquired. So it's baked into that it's actually 635 to be exact. I think but it's backed into that.

Brian Corales - Howard Weil

All right. And then just one other question I mean I guess we know about the backlog you had in Q1 and in Q2 you kind of had some operational hiccups. Looking at third quarter it looks like you're off to a very good start. I mean do you think these issues are behind you, is it just it sound like most have been rectified, but going forward I mean does what makes you most nervous about hitting the new guidance that you have put out today?

Baird Whitehead

All the products we have and I think John did a very thorough job on outlining some of the issues we had on working this four-and-a-half casing, three-stream Lavaca County. Even though five-and-a-half casing is only one inch bigger, it's world of difference in completion, in equipment that you get of working at five-and-a-half casing versus four-and-a-half casing. So I think the precautionary measures that John and his team have taken here recently I think is going to make a world of difference. If we're going to run into a problem here -- I mean, everybody does. So some people may not talk about it like we may amplify on this on cases to get the issues out in front of everyone but there well is the operational mechanical issues on trying to complete 6,000 foot laterals at 12,000 feet deep.

But I think having said all that, I think this 5..5 casing issue in most of our wells are going to be three string wells going forward. I think this 5.5 casing we've been able to run larger core tubing inside the drill our plugs I think will get beyond some of the issues we've run into.

As far as being nervous, I'm not real nervous. I mean, I realize we have to get these well suddenly in line. The big ramp up in the fourth quarter is based on the Welhausen and offsets where we have high working interest, and getting in turned in line of course in the fourth quarter. But I'm not very concerned about well quality associated with Welhausen well.

I think we've had a homerun in that specific area. Although the variance in results of wells are always are. But for the same reason, we drill to get Welhausen well and get margin well. Are those the best wells you're going run into? I don't think so. I mean, I think we'll probably drill some better wells than that, so we may drill some wells worse than that.

We've got to get more data of course. But at this point based on everything we've seen, we are all I think very excited about the Upper Eagle Ford potential.

Operator

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

Neal Dingmann - SunTrust

Probably a question for John first. John, I'm just wondering Baird talked obviously Upper Eagle Ford potential when you look at overall acreage. I guess my question is around here you certainly have the one monstrous well this quarter? When you look, is there something different on that well that you did? Or I guess what I'm trying to get a sense of is it just how the rocks are in different areas that sort of make the outcome? I wonder I guess, bottomline, that is are still changing, you're drilling and completion techniques to get results like that or is it just a matter if you're in the bear quadrant or it's just a matter of location?

John Brooks

Well, in the Welhausen, specifically those were - that well was drilled with five-and-half -inch casing so we were able to very effectively place all the proppants that we'd planned. Although, we had not achieved a 400,000 pounds per stage in the Welhausen. And so, there is a room to, hopefully, improve that.

In terms of the rock what we see in the bear quad area, number one is some higher temperatures. And in the Welhausen area, well, obviously, we're getting deeper and we're getting higher GORs. And in that Upper Eagle Ford, we've most likely got more eligible storage capacity and that in conjunction look the higher reservoir pressures leads to a very significantly shallower decline in early kind. In fact, the Welhausen well has kind of set our upper end of all our wells that we've drilled to date, in terms of early time data.

So to answer your question, the rock as you get deeper and get higher pressure in the Upper Eagle Ford with the higher reservoir capacity and the higher gas-oil ratios looks like its extending the productivity of the well meaningfully. And the five-and-a-half inch casing that we use in the Welhausen well, we're now going to be expanding that elsewhere; should result in getting more effective profit placement without screening out.

Neal Dingmann - SunTrust

And then just last one. As far as the additional rigs that are coming on, even the focus will be, I remember I spoke about this as far as in the new area. I'm just kind of wondering, I guess, I'm trying to get a sense -- now with eight rigs running and given that you have drilling in most of eight rigs, I'm trying to think about the drilling plan, maybe not just within the year, but in the '15; areas that you'll focus on, is it pretty spread out still? Baird or John or - how do you all think about that?

Baird Whitehead

Well we've got fairly from drilling schedule for most of our existing six rig fleet, as we have a rational basis for HVPing acreage number one and drilling obligation well, but also trying to drill our best wells first, obviously.

And we've extended that with the seventh and eight rig to drill our best net well first. we've got great wells in the bear quad area and bring them the seventh and eighth rig allows us to accelerate the fourth unit, the blonde unit, fully developed about a yearend in conjunction with fully developing the Welhausen unit by yearend as well.

So into '15, we'll see some more of the new acreage that we've recently acquired. Well, probably start off with one rig and add a second rig in development mode later in the year. So those two rigs are basically in 2014, we'll accelerate drilling our best wells and bet net well to get them online before yearend. And in 2015, we'll be further diluting and drilling Upper Eager Ford wells.

Operator

Thank you. And our next question comes from the line of Welles Fitzpatrick of Johnson Rice. Your line is open.

Welles Fitzpatrick - Johnson Rice

Can you guys talk sort of little bit about spacing in the moral specifically how tight you're going to be testing on this new wells and if you will be doing any Chevron patterns? And I guess, lastly, but on the same topic how the Chevron Martinsen 2H is holding up relative to the other two wells?

Baird Whitehead

John, why don’t you to take that please?

John Brooks

Okay. I'll answer your first question and the last question first. The Martinsen 2 is holding up very well as Baird mentioned to the point where we believe that’s a good case of 1 million BOE equivalent well.

So as to the Upper Eagle Ford spacing in the Welhausen we've got eight wells that will be drilled from 4-2 well pads and we will be testing a variety of spacing there from 500 up to 650 spacings. Among the laterals among the eight additional wells taking into account two existing wells. So, we'll see a variety of spacing there to fully develop that unit and be able to get a good feel hopefully some additional information on the optimal spacing area.

As far as the Chevron test, I think the RBK unit later this year which is the middle of our shiner more on the eastern side would the next Chevron pattern test that we will (inaudible) consist of a four well test.

Welles Fitzpatrick - Johnson Rice

Four wells between the two (inaudible) two and two?

John Brooks

Correct.

Welles Fitzpatrick - Johnson Rice

Just one last one, I apologize if I missed this, but I tend to see it in the release. Should we expect any changes to netbacks post the pipeline gathering deal?

Baird Whitehead

Welles, this is Baird. No, I mean, at the end of the day our transportation associated with this new gathering in Midstream intermediate line will be about the same as what we were incurring on the trucking side. So net net would be approximately zero. What it does is open up our flexibility on the marketing side as far as different places to take that crew, being able to get better prices on one line versus another, those kind of marketing advantages but its not going to change our netbacks and of course benefit we're getting $150 million upfront.

Operator

Thank you. And our final question comes from the line of Gail Nicholson of KLR Group. Your line in now open.

Gail Nicholson - KLR Group

Looking at the cost per stage savings in the quarter, has any of that contributed pad drilling?

Baird Whitehead

John?

John Brooks

Yes. With the efficiencies that we get in the pad drilling, as I mentioned, (inaudible) case, we can save about $140,000 per well by batch setting surface and utilizing the walking rig. Plus we've begun to providing all our drilling fluid that will save us a minimum of $100,000 per well that gets magnified on pad because your lower transport of carrying drilling fluid.

And on the completion side, when things go well they go really well and you see those costs come down. We've also been able to control the costs on our chemicals while we stepped our profit amount per stage just by varying and tightly engineering the fluids and profits upon schedules so that we get as much sand away with the least possible chemical and prop costs. So, to answer your question, yes, the pad drilling is generally always going to be significantly lower than a single well on a per stage basis.

Gail Nicholson - KLR Group

I guess I'm looking at a standpoint that when we look at the mechanical issues that you did kind of encounter on the number of wells in the quarter and as we take into account the pad drilling on the more as you do more of it as you move into the remaining of '14 and in '15 beyond, I would anticipate that that cost per stage saving for life that continue to improve as we move on to for the latter half of '14. Is that a fair assumption?

John Brooks

It is. I mean, it could be offset by externalities around service company costs that could come into play. Like I mentioned, we've put our stimulation services out for bid, we've got our results back, we're very pleased with it. I think we can maintain the high sand profit concentrations with pumping with maybe a 4% increase in the stimulation costs. I think some of that we can more tightly engineer our stimulation design and overcome that 4% cost in materials. So that and just getting better with the 5.5 inch and removing some of the mechanical challenges we should be able to get more stages per day away and that’s really what it comes down to.

In the earlier part of the year, we were not reaching our targets of five stages per day; it was probably closer to three and four stages per day. So going to the 5.5 inch casing should allow to get more stages away per day and that really is the key element for us. And as well on the core tubing drill, as Baird mentioned, the 5.5 inch casing we can use the larger core tubing, but not only that but as we have provided our own joint fluids and joint fluid engineering services we've dovetailed that with our chemical side on our core tubing drill outs and being able to reduce some of the cost of the high viscosity suites that are used to drill out those flood so that we can get that done quicker, cheaper and with less mechanical risk.

Gail Nicholson - KLR Group

Okay. And then looking at this team and the execution of doing the best acreage and the best net wells first now, is it fair to assume that we're not going to see much as any activity on those shallower areas of the acreage?

Baird Whitehead

Gill, that’s correct. This is Baird. Even though we have drilled some excellent wells in the shallower acres in general, the shallower acreage has been deemphasized going forward.

Gail Nicholson - KLR Group

And what's the -- I mean, out of that 1650 net gross locations have I mean, I think the last quarter you guys sent out a information say about 233 weren't that shallow. Is that still a fair number for shallow location?

Baird Whitehead

That is. I mean, shallow locations are still very economical. They just have lower IP rates, have lesser early declines but we have drilled this (inaudible) Nashville we drilled is pretty close to this shallow acreage and it’s an excellent. So we can't eliminate all shallow wells because I wish geology was that simple but its not, but there are overall reasons why we want to deemphasize the shallower acreage and spend our money on deeper acreage. Shallow acreage is not going away. Almost all of it is HPT in those cases so, we've earned it.

Gail Nicholson - KLR Group

Okay. And then looking at the standpoint of when you look at the entire acreage position and what you have location count on the Upper Eagle Ford, what is your compositional expectation of your Upper Eagle Ford wells? I mean, the well has an area looks a tad bit gassier but I wasn’t sure maybe if the new acreage that you picked up is a little bit -- oilier based on some of the offset operator activity.

Baird Whitehead

The acreage we picked up probably going to have similar GORs but let me remind you that even though the GOR is higher in quantity that oil and oil reserves are about the same as to what we typically drill in a lower Eagle Ford a the heart of our acreage. So the way we look at is we're drilling higher reserve kind of wells that have an oil makeup that’s at least as good, if not better than what we typically drill, and then it has a very strong NGL calling it associated with the post processing along with the residue gas. So the percent of oil comes down in quantity the overall well is at least as good, if not better, is what we typically see.

Operator

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

Scott Hanold - RBC Capital Markets

Just a couple of quick follow-ups here. Just more clarification the terms in the Midstream deal. There's not a material change in the cost. Just to begin help refresh me, I think you sell your oil, what does it cost like, $6, $7 to transport it and market it, the LLS price market, is that right? So that's about what we are all expecting on this -- for the Midstream agreement.

Baird Whitehead

Yeah. In general, you could estimate probably around $4 per barrel in general. There are different thresholds, different rates. But in general, you could use probably around $4 a barrel. For our gathering and intermediate line there would be some down stream transportation on top of that in a third party line. So net-net, we get to the $6 to get it to the LLS market.

Scott Hanold - RBC Capital Markets

Okay. All right. And that's great. And then, the other one is just on the performance of the Upper Eagle Ford wells, like the Welhausen in the Martinsen intermediate, it seems to be holding in pretty well and I mean is it above your all expectations? And why do you think that -- it is just because you are not opening the choke or what would you attribute to the given that strong kind of volumes you are getting from that?

Baird Whitehead

Well, I think it's -- John sort of discussed it was it's gassier. I mean, I realize gas as a very negative connotation in today's world. But from a reservoir standpoint and recovery standpoint having little bit of gas actually helps and improves your recoveries. And I think the choke maintenance, we have not -- because it is gas it is -- we have managed the choke size. I can't tell you right now what our up string pressures are or the choke. But they are still materially higher than what the line pressure is.

So a combination of those two, plus I think the reservoir itself -- the Upper Eagle Ford is a more calcareous reservoir. There are reasons to think that when you frac the stuff because it is harder, more brittle that you get a more affect, effective induce frac geometry. So there are reasons to think that we are getting the stuff busted up better in the upper because it's harder and more brittle. And will be extremely interesting to see on the pad drilling and the advantages of zipper fracs, if it helps to resolve that much more because it -- theoretically it should. I think those are the few reasons why the upper is acting better.

Scott Hanold - RBC Capital Markets

What is the GOR done from like the first 24 hours 30 days than what you have seen in the most kind of recent flow rates?

Baird Whitehead

They are still hanging around 4500 to 5,000 to 1.

Scott Hanold - RBC Capital Markets

Okay. So it remained pretty confident. Okay. That's good.

Baird Whitehead

It has.

Operator

Thank you. And our next question comes from the line of David Tameron of Wells Fargo. Your line is now open.

David Tameron - Wells Fargo

Hi. So I'll just -- I'll keep it brief here just because we're up against the hour. But if I can think about production ramp, can you guys outline if the second half of the year and the fourth quarter number. How should be think about going into 2015 in order to get to both -- I guess I'm looking for an exit rate, kind of year on exit rate. Can you give us something or give us some framework around that?

Baird Whitehead

Steve?

Steve Hartman

Steve. Believing that exiting 2014, we would expect it to probably be now over 30,000 like 30,000, 32,000 a day, David.

David Tameron - Wells Fargo

Okay. That's helpful. And then --

Steve Hartman

For the fourth quarter.

David Tameron - Wells Fargo

I'm sorry. Steve, you said for the -- you said in Q4 at 30,000 to 32,000?

Baird Whitehead

This is Baird. Actually our fourth quarter will probably around 28,000 or so.

David Tameron - Wells Fargo

Okay. Well, that's okay. So the other rate, Steve, is kind of 30,000 to 32,000 exit rate going under 2015?

Baird Whitehead

That could have been in December, right.

Steve Hartman

Yeah.

David Tameron - Wells Fargo

Okay. That make sense. And then, if I think about 20 -- how should I think about the oil gas split? How has that evolved over the next? I know you've guided the 45% oil growth in '15, but how should we think about that oil gas split as we think about the next four or five quarters?

Baird Whitehead

The gas split may go up, probably will go up somewhat because the Welhausen in it Upper Eagle Ford emphasis in general. I can't say, it's again watching Lavaca County exactly what that GOR is going to do. It probably would be less than the well has. Because as you go deeper it goes to the east, GOR should theoretically increase. But I'd say, I think we typically had around 85% liquids, 15% gas, is that correct? In general, I think that we may go to 80/20, or 75/25 over time as we add more gas, but it's not going to be materially different than what we see right now.

Operator

Thank you. And our next question comes from the line of Steve Berman of Canaccord. Your line is now open.

Steve Berman - Canaccord

Good morning. Thanks for all the detail. Most of my question have been asked and answered. Just a couple on the liquidity front. Steve, can you clarify that $630 million of pro forma liquidity, does that exclude Magnum Hunter arbitration award?

Steve Hartman

No, that includes it.

Steve Berman - Canaccord

That includes it. Okay. And then, with the oil gathering transaction in the mids, the so much choke about the close, what are you current thoughts on still positively monetizing the Granite Wash?

Baird Whitehead

There is less and less chance to really get that done. We've had a few offers that didn't meet our expectations, its still on the market. There is one party still looking at it. But considering it's still generating, I don't know around $20 million a year EBITDAX there is no reason to give it away. So, we are not spending money out there. We have reached and exceeded our original goal that we had beginning of the year to $300 million. So at this point in time, we will keep it in an all like we did, we will up end up keeping it.

Operator

Thank you. And our next question comes from the line of Kim Pacanovsky of Imperial Capital. Your line is now open.

Kim Pacanovsky - Imperial Capital

Hi. Good morning everyone. I realize that you still leased to have about four months of production history remaining until the end of the year. But have you had any preliminary discussions with Writer Scott on the Upper Eagle Ford wells and having might be booked?

Baird Whitehead

We're actually use Writing Company, it's our third quarter.

Kim Pacanovsky - Imperial Capital

Oh, sorry. Right. Sorry about that.

Baird Whitehead

All right. Good morning. I have to go to Writer Scott, Writing it's our first. We have not had any preliminary discussion with him. If you look at the early time information, as John pointed out, these things have a very shallow decline associated with it. So third party engineer typically is not going to stick our neck out when we don't have a lot of information, it's a very compelling case. To make at least a $1 million as I pointed out in Welhausen, there is a very compelling case to make it a much higher number. But I don't have a number at this time what our third party engineers may do, but I think it's going to be -- I think we will be happy with it. And I think over time that number is going to go up.

Kim Pacanovsky - Imperial Capital

And then, on your 2015 preliminary guidance, how are you looking at the split of Upper Eagle Ford and Lower Eagle Ford wells? I mean that kind of goes back to Gail's question about if you're drilling up the higher IRR wells first could we really see a big shift to Upper Eagle Ford in 2015?

Baird Whitehead

I can't give you an exact split. But yes, we will continue to drill the best wells we can in the lower across our overall acres, but you will see a more of a higher ratio in Upper Eagle Ford wells drilled. And if I have to guess, it probably would be around 50/50.

Kim Pacanovsky - Imperial Capital

Okay. And then, just finally, with the gas markets, can you just give us an idea what you are looking at with regards to hedging for 2015?

Steve Hartman

Well, we haven't been hedging natural gas. We have been concentrating on oil. So 2015, we were about 53% hedged to the mid point of guidance. But for natural gas, our last natural gas hedge rolls up in the first quarter of '15 and we are not hedging in these prices.

Operator

Thank you. And our next question comes from line of Subhash Chandra of Jefferies. Your line is now open.

Subhash Chandra - Jefferies

Yeah. Again, apologizes. This is the (inaudible) on the call, try keep it short. The minimum volume commitments on the new Midstream facilities, can you comment on those?

Baird Whitehead

Yeah. I think it was in the press release, if not mistaken. But I -- it's 15,000 barrels a day as a gross number. So -- and it really is not much risk associated with that.

Subhash Chandra - Jefferies

All right. And how should be net that number out?

Baird Whitehead

I'm not sure I understand that question, Subhash.

Subhash Chandra - Jefferies

Yeah. I'm sorry. So what would the net volume be?

Baird Whitehead

Oh, to our interest of working it?

Subhash Chandra - Jefferies

Yeah.

Baird Whitehead

I'll tell you as far as a weighted average goes it would probably be around 70% to 80%.

Subhash Chandra - Jefferies

Okay. Got it. Thanks. And there is no escalator to that number, so that number stays flat that's flat minimum volume commitment or does that rise over time?

Baird Whitehead

It's a flat number and I think it's for 10 years, if I'm not mistaken.

Operator

Thank you. And our final question comes from the line of Richard Tullis of Capital One. Your line is now open.

Richard Tullis - Capital One

Hey. Thanks. Good morning everyone. Just a quickly. Steve, on the real nice sale price that you guys got for the oil pipeline rights that $150 million, what's the expected tax impact on the gain there and any current tax associated with that?

Steve Hartman

Rich, we have our NOLs we are still working through. So we will have to pay some tax. I don't remember the exact number, but I want to say it was probably in the $4 million to $5 million range. But for the most part, we will be able to shelter most -- almost all of it with the NO wells.

Richard Tullis - Capital One

Okay. And then, lastly, just moving on to the well cost. I know you touched on it little bit a couple calls back. But do you think you can get the well cost per stage down closer to say the $300,000 per stage for Peach Creek and $340 for Shiner that's been highlighted in the recent slide decks?

Baird Whitehead

John.

John Brooks

Well, a large part that's going to be driven by the market with profit. But I think we haven't begged in any of the continuous improvements that we have seen, but the 12% increase of our rate of penetration kept it drilling the big rigs. So there is some constrains on the commercial side and from outside on things that we can control. But on the things that we can't control that could be achievable but that would be driven to some extent by the amount of same volume that we thought.

Operator

Thank you. And I am showing no further questions. At this time, I would now like to turn the call back over to Mr. Baird Whitehead for any closing remarks.

Baird Whitehead

All right. Thank you, Candice. I just want to point out, if you look at this company three years ago we have -- we were almost primarily a natural gas company. We chased it significantly. We haven't assembled a very attracted Eagle Ford asset. We have taken a small 6,500 acre position from late 2010 and we have made in a much larger of course and hot quality footprint of over 100,000 acres right now. We have taken our Eagle Ford oil production and averaged about 2,300 barrels a day in 2011. To now, which is estimated an excess of 90,000 barrels a day equivalent in '14. And we expect another 45% increase in 2015. We have taken a drilling inventory that was almost nil in late 2010 and made it over 1600 locations. Today, in some part of our acreage we have got the stack pay potential in both the Upper and Lower. And we think the Upper Eagle Ford can provide a significant upside for Penn Virginia over time as evidence by these recent results in a Welhausen and Martinsen wells. All of these attributes we think are going to provide a significant growth opportunity [Call ends abruptly].

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Penn Virginia (NYSE:PVA): Q2 EPS of -$0.07 misses by $0.02. Revenue of $136.43M (+24.3% Y/Y) misses by $13.17M. Shares -1.98% AH.