Ranger Oil Corp (ROCC) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation second quarter 2014 earnings call.

(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.

All right. Thank you very much, Candace, and thank you all for joining us today for Penn Virginia's 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 of 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 related 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 and streamline our drilling 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 will continue to improve.

The IPs, along with the 30 day rates of the wells completed and turned in line in this most recent quarter, reflect the longer-term trend of improved IPs 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, as we pointed out in the press release, will drive our production increase later in the year and again into 2015.

Now moving on to some of the highlights for the quarter. The 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 1070 barrels equivalent per day over the first 95 days, 1519 barrels oil equivalent per day over the first 60 days. The Martinsen 2H well was turned in line in May 2014 and has averaged 1149 barrels 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 type 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, 1 million barrels of oil equivalent in ultimate reserves. In fact, there's a case for the Welhausen well to be closer to 1-1/2 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 cum to date is 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 cum to date of this well is 100,000 barrels equivalent.

Currently I want to point out the Welhausen well after almost 4 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 of 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 fit with our current Shiner acreage in Lavaca County. With this acreage, this acquisition, we are now at approximately 102,000 net acres in the play, exceeding the 100,000 acre minimum goal that we put in place at the beginning of the year.

Let me emphasize that this was a minimum target. We're not done yet. We will continue to expand our position by primarily looking in our backyard with an ongoing leasing effort.

Our 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 our shareholders.

As I have pointed out in the past, to illustrate the growth and value, if you buy an Eagle Ford acre for about $3500, drill it with a $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, it 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 the recent acquisition in an average cost of about $3700 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 a remaining drilling inventory that filters over 1600 locations, 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 1510 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 where both the upper and lower intervals would be both productive. There could be as many as many as 400 additional upper Eagle Ford locations in our western Lavaca County acreage.

What we plan to do is to drill some additional upper 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 have already spud, and those eight wells will be drilled from four different pads. In addition, we will further increase our upper Eagle Ford program in order 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 raise between about 8.8 million 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 to 5.3 million barrels. This implies growth in total 2014 production of 30% to 35% over 2013, and a 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 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 $150 million. This sale, together with the sale of gas gathering and gas-lift systems early in the year for $96 million and the expected 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 of $300 million earlier 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're now in a very comfortable position to fund the CapEx program not only for this year, but planned for the remainder of next year also.

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.

Thank you 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, as Baird touched on, was less than expected, primarily in April and May, given delays in the timing of a number of completions. Much of that due, in no small part, to a dramatic increase in completion inventory that followed our ramp up in drilling activity. In June 2014 our production was over 23,000 barrels of oil equivalent per day. And in July through 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 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 high 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 modest increase over the second quarter.

Year to date, we have turned in line 43 gross, 28.0 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 an 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 operating 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 and 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 operating wells. These wells have an average IP of 1514 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'd at 3175 barrels of oil equivalent per day, and that's a company record for us, over 26 frac stages. The Cinco Ranch LTD unit number 1H, 2611 barrels of oil equivalent per day over 32 frac stages. The Bock number 6H, 2272 barrels of oil equivalent per day over 26 frac stages. The Amber 1H, 2217 barrels of oil equivalent per day over 23 frac stages. The Amber 2H, 1919 barrels of oil equivalent per day over 22 frac stages. And the Wombat number 1H, 1670 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, namely the Bock unit. This was the fourth unit in the Beer Quad and all seven wells came online in the last week of June. These wells were all drilled in the lower Eagle Ford on 400 foot lateral spacing, and involved pumping a total of 183 stages averaging over 400,000 pounds of proppant per stage. The sum of the IPs from this seven well unit exceed 12,000 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 their location of the Beer Quad area near Shiner, the Peach Creek area, and the Rock Creek Ranch/Bozca areas.

Turning to the upper Eagle Ford, it suffices to say that early time well production was far exceeding expectations. 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 the 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 most prolific reservoir. 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's 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 the 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 1510 to approximately 1635 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've encountered of late. Operational challenges encountered on multiwell pads are obviously magnified and sometimes multiplied by the well counts on the pad in question. In particular, we had two four-well pads when this occurred in the second quarter. In Gonzales County on our Rock Creek Ranch Wyatt four-well pad, all four wells were programmed to TD at their respective lateral lengths and yield a total of 139 stages for fracking.

While drilling, we encountered geologic faulting near the toe of the laterals that resulted in lost circulation. This in turn led to shorter effective 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 Hunter unit. As you are probably aware our Peach Creek wells largely in Gonzales County, are two stream wells, while in Shiner, in Lavaca County, higher pressures require a third casing stream. The pressure transition, however, is not as simply demarcated as the county line.

All four Wombat wells were drilled downdip 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 completable 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 corrective measures we've taken include reprocessing our 3D seismic data to better image geologic faulting and subsurface complexity. Additionally, identifying this pressure transition in the northern regions of Peach Creek should help us avoid similar situations going forward.

In Lavaca County the challenges were more mechanical in nature. Historically we've set 4-1/2 inch casing as our third casing stream. Working in 4-1/2 inch casing at high temperatures and pressures presents challenges in drilling, completion, and production.

On the drilling side, the smaller tools used in the 4-1/2 inch casing well design require NWD and directional tools that have a meaningfully shorter life downhole, further complicated by the higher temperatures we see in Lavaca County, especially in the Beer Quad.

On the completion side, the 4-1/2 inch casing requires more horsepower and results in a lower maximum treating pressure. As we've ramped up our sand volume, this lower maximum treating pressure constraint has frequently resulted in premature screen outs. This, in turn, often requires a coiled tubing cleanout in the middle of a frac job, which can result in additional cost, delays, and, importantly, not getting all the proppant in place. The 4-1/2 inch casing also has a higher incident rate of mechanical difficulties in plug-and-perf operations which also causes delays, additional costs, and sometimes lost 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 corrective measure we have instituted here is to upsize the well bore in our three string wells, with the goal of having 5-1/2 inch casing as our production casing. We've also installed mud coolers in our hot hole area that cool the drilling mud before pumping downhole which yields longer tool life and ultimately greater effective rate of penetration.

The larger 5-1/2 inch casing should result in lower horsepower requirements, higher allowable treating pressures, more effective sand placement, and less 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 indications so far is that this change in 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 have been running about $120,000 to $135,000 per stage as we continue to ramp up total sand volumes to roughly 1800 pounds of proppant per lateral foot. In addition, the amount of proppant 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 negotiations for the next 12 months stimulation services with multiple service providers. These contracts are expected to be one-year contracts and we're confident that any cost increases will not be substantial from what we've seen so far.

We continue our other cost-reducing or 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 and casing the laterals without having to lay down and pick up drill pipe repeatedly.

On our three-stream wells this saves us, on average, an estimated $140,000 and over 100 hours per well.

For the first half of 2014, utilizing these and several other innovations, we've increased our effective footage drilled per day by 12% compared to 2013. As mentioned, we've also reduced our costs 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.

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 liquids sales were $120.1 million which is 5% higher than the previous quarter. The primary drivers were 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 cost, chemical cost, and fuel lubricant cost, 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 nonrecurring expenses related to our recent accounting system installation which is now complete, non-core asset sales 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 a $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 had higher than anticipated inventory wells waiting on completion at the end of the first quarter. We caught up a lot of that backlog with 25 wells turned in line during the second quarter compared to 16 wells turned in line during the first quarter. Leasehold acquisition 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. Concurrent with the issuance of the Series B preferred stock, we have converted about 23% of the Series A depository shares into 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 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'll take a $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've 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 the seventh rig in August and the eighth rig in September. Our lease acquisition guidance has 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 $30 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 is 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 1750 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 of 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 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 start to see production contributions from the seventh and eighth rigs kick in. Our production numbers for June and July as John outlined are on track with this type of growth.

We're 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 for the credit facility balance right now is set at zero to $65 million. Our leverage should exit 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 the $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 saw, or 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 to 2.2 times and our liquidity at the end of 2015 should remain at $300 million or better, assuming we receive borrowing base 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 be fully funded with cash flows by 2017.

Baird, that concludes financial results and guidance.

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

(Operator Instructions)

Brian Corales, Howard Weil.

Good morning, guys. A couple quick questions, and maybe I'll start with you, Baird. The upper Eagle Ford, you've had some great results, how much of the current acreage position, do you think, is prospective, one? And then two, how much have you tested?

As far as what we think is prospective, especially with this recent acquisition we made which the merits of which were primarily based on the upper -- I'd estimate at this time probably around 60% to 70% of our acreage as prospective in the upper.

A good rule of thumb is the Gonzales, Lavaca County line is probably a pretty decent line of demarcation where we think the upper is prospective going east.

As far as what percent of our acreage 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 acreage on trend with the Martinsen and Welhausen and there is a Schuster well and a Tarjack well, if memory serves me correct. 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 the acreage we just picked up, that we announced. Really what we need to do is get our western Lavaca County acreage tested.

But at this point in time, based on a lot of characteristics of whatever pilot wells we may have drilled to react our overall development program in the Eagle Ford and Holly openhole logs look in some of the shows we have as we're drilling through this stuff, even drilling lower Eagle Ford wells, I think we all have a high degree of confidence that this is going to work out just great for us. We are drilling -- starting to drill 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 developing the upper as we would typically develop the lower, so I probably told you more than what you asked, but (multiple speakers) about the upper at this time.

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

We actually threw out 150 locations for the upper on the acreage that we acquired. So it's baked into that -- it's actually 635, to be exact, I think. But it's baked in there.

All right. And then, just one other question.

I guess we know about the backlog you had in 1Q and in 2Q you kind of had some operational hiccups. Looking at third quarter, it looks like you are off to a very good start. Do you think these issues are behind you?

It sounded like most of them have been rectified. But going forward, what makes you most nervous about hitting the new guidance that you have put out today?

Are all the problems behind us? I think John did a very thorough job on outlining some of the issues we've had on working this 4.5-inch casing, in our three stream Lavaca County -- even though 5.5-casing is only one inch bigger, it is a world of difference in completion and in the equipment that you get of working on 5.5 casing versus 4.5. I think the precautionary measures that John and his team have taken here recently I think is going to make a world of difference.

Are we going to run into a problem here and there? Everybody does. So some people may not talk about it like we may amplify on in some cases just to get the issues out in front of everyone. There will always be operational and mechanical issues on trying to complete 6000 foot laterals at 12,000 feet deep.

But I think having said all that, I think this 5.5 casing issue and most of our wells are going to be three-stream wells going forward, I think this 5.5 casing and being able to run a larger coil tubing inside the grow out plugs will get beyond some of the issues we've run into.

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

I think we've hit a home run in that specific area. Will there be variants in results of wells? There always are.

But for the same reason we drilled a good Welhausen well and a good Martinsen well, are those the best wells you're going to run into, I don't think so. I think we'll probably drill some better wells than that, but we may drill some wells worse than that; we've got to get some more data of course. But at this point in time, based on everything we've seen, we are all very excited about the upper Eagle Ford potential.

Neal Dingmann, SunTrust.

Good morning, guys. Probably a question for John first.

John, I'm just wondering, Baird talked about upper Eagle Ford potential when you look at your overall acreage. I guess my question is around, you certainly had that one monster 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'm wondering I guess bottom line, are you still changing your drilling and completion techniques to get results like that or is it just a matter of if you are in the Beer Quadrant or it's just a matter of location?

On the Welhausen specifically, that well was drilled with 5.5-inch casing so we were able to very effectively place all the proppants that we had planned. Although we had not achieved a 400,000 pounds per stage in the Welhausen. So there's room to hopefully improve that.

And in terms of the rock, what we see in the Beer Quad area, number one, is some higher temperatures and the Welhausen area obviously we're getting deeper and we're getting higher GORs. And in the upper Eagle Ford, it looks like we've got more reservoir storage capacity, and that in conjunction with the higher reservoir pressures leads to a very significantly shallower decline in early time. In fact, the Welhausen wells have kind of set our upper end of all our wells 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 it's extending the productivity of the well meaningfully. And the 5.5-inch casing that we used in the Welhausen, and we're now going to be extending that elsewhere, should result in getting more effective proppant placement without screening out.

Okay. And then just one last one as far as the additional rigs that are coming on.

Will the focus be -- I don't remember, I spoke about this as far as in the new area, I'm kind of wondering trying to get a sense of now eight rigs running and given that you have delineated most of your acreage, I'm trying to think about the drilling plan maybe not just for the end of the year but into 2015, areas you will focus on. Is it pretty spread out still, Baird or John, or how are you going to think about that?

We've got a fairly firm drilling schedule for most of our existing six-rig fleet as we have a rational basis for HBP acreage number one and drilling obligation wells, but also trying to drill our best wells first, obviously. We've extended that with a seventh and eighth rig to drill our best net wells first. We've got great wells in the Beer Quad area and bringing the seventh and eighth rig allows us to accelerate the fourth unit the blonde unit fully developed by the year end in conjunction with fully developing the Welhausen unit by year end as well.

Into 2015, we'll see more of the new acreage that we've recently acquired. We'll probably start off with one rig and add a second rig in development mode later in the year. Those two rigs basically in 2014 will accelerate drilling our best wells and best net wells to get them online before year-end and in 2015 we'll be further delineating and drilling upper Eagle Ford wells.

All right. Thanks, guys.

Welles Fitzpatrick, Johnson Rice.

Good morning.

Hello, Welles.

Can you guys talk a little bit about spacing in the Marl, specifically how tight you're going to be testing on those new wells and if you'll 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 two other wells?

John, why don't you take that, please.

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

As to the upper Eagle Ford spacing and the Welhausen, we've got eight wells that will be drilled from four two-well pads. And we will be testing a variety of spacing there from 500 up to 650 spacing between laterals among the eight additional wells, taking into account the 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 for hopefully some additional information on the optimal spacing units.

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, will be the next Chevron pattern test that we will and I think that will be a -- consist of a four-well test.

Four wells between the two down, so two and two?

Correct.

Okay, perfect. Thanks.

Just one last one, I apologize if I missed it, but I didn't see it in the release. Should we expect any changes to your netbacks post the pipeline, the gathering deal?

Welles, this is Baird. No, at the end of the day our transportation associated with this new gathering and midstream intermediate line will be about the same as what we were incurring on the trucking side. So net-net, it will be approximately 0.

What it does is open up our flexibility on our marketing side as far as different places to take that crude being able to get better prices on one line versus another, those kind of marketing advantages. But it's not going to change our netback and of course the benefit we're getting $150 million upfront.

Great. Thanks so much.

Gail Nicholson, KLR Group.

Good morning, gentlemen. Looking at the cost per stage savings in the quarter, is any of that contributed to pad drilling?

John?

Yes. With the efficiencies that we get on the pad drilling as I mentioned say in a three stream case we can say it's about $140,000 per well by back setting surface and utilizing the walking rigs. Plus we've gone to providing all of our own drilling fluid; that will save us a minimum of $100,000 per well, that gets magnified on pads because your lower transport cost of cuttings and 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've stepped up our proppant amount per stage just by varying and tightly engineering the fluids in the proppant -- our pump schedules. So that we get as much sand away with the least possible chemical and prop cost.

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.

I guess I'm looking at it from the standpoint, 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 and as you do more as you move into the arraigning of 2014 and 2015 and beyond, I would anticipate that cost per stage of savings would likely continue to improve as we move on for the latter half of 2014. Is that a fair assumption?

It is. It could be offset by externalities around service company cost that could come into play. As I've mentioned we've put our [motion] services out for bid. We've got our results back. We're very pleased with it.

I think we can maintain the high sand proppant concentrations we're pumping with maybe a 4% increase in the stimulation cost. I think some of that we can more tightly engineer our stimulation design and overcome that 4% cost in materials.

That and getting better with the 51/2 inch and removing some of the mechanical challenges, we should be able to get more stages per day away. That's really what it comes down to.

In the earlier part of the year, we were not reaching our target of five stages per day, it was probably closer to three and four stages per day. Going to the 5.5-inch casing, should allow us to get more stages away today and that really is the key element for us.

As well on the coil tubing drillouts, as Baird mentioned in the 5.5-inch casing, we can use the larger coil tubing. But not only that, as we have provided our own drilling fluids and drilling fluid engineering services, we've dovetailed that with the chemical side on our coil tubing drillouts and being able to reduce some of the cost of the high viscosity sweeps that are used to drill out those plugs so that we can get that done quicker, cheaper and with less mechanical risk.

Okay. And then looking at 2015 and the expectation of drilling the best acreage and the best net wells first now, is it fair to assume that we're not going to see much, if any, activity on those shallower areas of the acreage?

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

Out of the 1650 net -- the 650 growth locations you have I think the last quarter you guys sent out some information that said 233 were in that shallow. Is that still a fair number for shallow locations?

That is. Shallow locations are still very economical. They just have lower IP rates, have lesser early declines. But we have drilled -- this Cinco Ranch well we drilled is pretty close to the shallow acreage and it's an excellent well.

So we can't eliminate all shallow wells because I wish geology was that simple but it's not. But there are overall reasons why we want to deemphasize the shallower acreage and spend our money on deeper acreage. The shallow acreage is not going away, almost all of it is HBP in most cases, so we've earned it.

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 the compositional expectation of your upper Eagle Ford wells? The well has an area that looks a tad bit gassier, but I wasn't sure if maybe the new acreage that you picked up is going to be a little bit oilier based on some of the offset operator activity.

The acreage we picked up is probably going to have similar GORs. Let me remind you that even though the GOR is higher in quantity to oil and the oil reserves are about the same as what we typically drill in the lower Eagle Ford, in the heart of our acreage. So the way we look at it 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 component associated with the post processing along with the residue gas. Even though the percent of oil comes down in quantity the overall oil is at least as good if not better as what we typically see.

Okay, great. Thank you so much.

Scott Hanold, RBC Capital Markets.

Thanks. Just a couple of quick follow-ups here.

Just more clarification on the terms in the midstream deal. I think, Baird, you said there is not a material change in the cost -- just if you can help refresh me. I think to sell your oil, what does it cost, $6, $7 to transport it, to get it to market, the LLS priced market, is that right? So that's about what we're all expecting on the sort of midstream agreement?

Yes. 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 and there would be some downstream 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.

That's great. And then the other one is just on the performance of the upper Eagle Ford wells like the Welhausen and the Martinsen, it seems to be holding in pretty well and is above your expectations. Why do you think that is? Is it just because you are not opening the choke or what would you attribute to the strong kind of volumes you're getting from that?

Well I think it's, John sort of discussed it, it's gassier. I realize gas is a very negative connotation in today's world, but from a reservoir standpoint or recovery standpoint having a little bit of gas actually helps your -- improves your recoveries. And I think the choke maintenance, we have not -- because it is as gassy as it is, we have managed the choke size.

I can't tell you right now what our upstream pressures are of the choke, but they're 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 this stuff because it is harder, more brittle, that you get a more effective induced frac geometry. So there are reasons to think that we're getting this stuff busted up better in the upper because it's harder and more brittle. And we'll be extremely interested in seeing on the pad drilling and the advantages of zipper fracs if it helps the result that much more because theoretically it should. I think those are a few reasons why the upper is acting better.

What has the GOR done from the first 24 hours, 30 days, to what you've seen in the most kind of recent flow rates?

It's still hanging around 4500 to 5000 to 1.

So it's remaining pretty constant. That's good.

It has.

Okay, thanks, that's good.

Thank you.

David Tameron, Wells Fargo.

Good morning. I'll keep it brief here since we're up against the hour.

But if I think about the production ramp and you guys outlined this second half of the year and the fourth quarter number, how should we think about going into 2015 in order to get to those -- I guess I'm looking for an exit rate, kind of year end exit rate. Can you give us some framework around there?

Steve?

Exiting 2014, we would expect it to probably be over 30,000, 32,000 a day, David.

Okay. That's helpful.

Fourth quarter.

I'm sorry, Steve, you said 4Q at 30,000 or 32,000?

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

Okay. So the other rate, Steve, was kind of 30,000, 32,000 exit rate going into 2015?

That could have been the December rate, yes.

That makes sense. How should I think about the oil/gas split, how does that evolve over the next -- I know you've guided to 45% oil growth in 2015. But how should we think about that oil/gas split as we think about the next four or five quarters?

The gas split will probably go up somewhat because of the Welhausen and upper Eagle Ford emphasis in general. I can't tell you, as we get in western Lavaca County, exactly what that GOR is going to do. It probably will be less than the Welhausen, because as you go deeper and go to the east, the GOR should theoretically increase.

But I'd say I think we typically have 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 is not going to be materially different than what we see right now.

Okay. That's helpful. Thanks for all the color.

Steve Berman, Canaccord.

Good morning. Thanks for all the detail. My question has been asked and answered just a couple [according to] front. Steve, can you clarify that $630 million of pro forma liquidity, does that exclude the Magnum Hunter arbitration?

No, that includes it.

Okay. And the with the oil gathering transaction and the summer talk about the close, what are your current stocks on still possibly monetizing the Granite Wash?

There's less and less chance we're going to get that done. We kind of had a few offers that didn't meet our expectations, its still on the market, there's one party still looking at it. But considering it's still generating around $20 million a year of EBITDAX, there's no reason to give it away.

So we're not running money up there. We've reached and exceeded our original goal that we had at the beginning of the year to $300 million. So at this point in time we will keep it, and in all likelihood we will end up keeping it.

Great. Thank you.

Thank you.

Kim Pacanovsky, Imperial Capital.

Hello, good morning everyone. I realize that you still have about four months of production history remaining until the end of the year. But have you had any preliminary discussions with [writers] Scott on the upper Eagle Ford wells and how they may be booked?

We actually use writing company as our third-party

Oh sorry. Right.

I'd be more hype heavy to go to writer Scott, but -- we have not had any preliminary discussions with them. If you look at the early timing information, and as John pointed out, these things have a very shallow decline associated with it.

Third-party engineer typically is not going to stick their neck out when they don't have a lot of information. There's a very compelling case.

To make at least $1 million, according to. Welhausen there's a very compelling case to make it a much higher number. I don't have a number at this time. What our third-party engineer's may do but I think it's going to be, I think we'll be happy with it. I think over time that number is going to go up.

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

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 acreage but you will see a more higher ratio of upper Eagle Ford wells drilled. And if I had to guess it probably would be around 50/50.

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

We haven't been hedging natural gas -- we been concentrating on oil. So we took 2013 and were about 53% hedged to the midpoint of guidance. But for natural gas our last natural gas hedge rolls off in the first quarter of 2015 and we're not hedging at these prices.

Okay. Great. Thanks a lot guys.

Thank you.

Subash Chandra, Jefferies.

Again, I apologize if this was addressed earlier in the call; I'll keep it short. The minimum volume commitments on the new midstream facilities, can you comment on those?

I think it was in the press release if I'm not mistaken, but it's 50,000 barrels a day. That the gross number. And it really is not much risk associated with that.

Right. How should we net that number out?

I'm not sure I understand that question Subash.

I'm sorry what would the net volumes be?

Oh to our interest, --

Yes.

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

Okay. Got it. Thanks.

And there's no escalator to that number? So that number stays flat, that are flat volume or does that rise over time?

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

Got you. Perfect thank you very much.

Thank you.

Richard Tullis, Capital One.

Thanks, good morning everyone. Just quickly, Steve on the real nice sale price that you guys got for the oil pipeline rights $650 million, what's the expected tax impact on the gain there and any current tax associated with that?

We have our wells we're still working through, so we will have to pay some tax. I don't know the exact number but I want to say it is probably in the $4 million to $5 million range, but for the most part will be able to shelter almost all that with the NOLs.

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

John?

A large part of that is going to be drilling by the market for-profits.b Bt I think we haven't baked in any of the continuous improvement that we've seen like the 12% increase of our penetration rate in effective drilling of the big rigs. So there's some constraints on the commercial side from outside with the things that we can control. But on the things that we can't control, that could be achievable, but it will be driven to some extent by the amount of sand volume that we pump.

Okay. That's all I have. Thanks a bunch.

Thank you Richard.

Thank you and I'm 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.

Alright Candace. I just want to point out that if you look at this company three years ago where we have -- we were almost primarily a natural gas company, we've changed it significantly and have assembled a very attractive Eagle Ford asset.

We've taken a small 6500 acre position from late 2010, we've made it a much larger of course and high-quality footprint of over 100,000 acres right now. We've taken our Eagle Ford oil production and averaged about 2300 barrels a day in 2011, to now which estimated an excess of 90,000 barrel a day equivalent in 2014, and we expect another 45% increase in 2015.

We've taken a drilling inventory that was almost nil in late 2010 and made it over 1600 locations. Today on some part of our acreage we've got this stack A potential in both the upper and lower. We think the upper Eagle Ford can provide a significant upside for Virginia over time as evidenced by these recent results in the Welhausen and Martinsen wells.

All of these attributes are going to provide significant growth opportunities which we believe create further shareholder value going forward and I just wanted to point that out. So I want to thank you for all participating on this quarter's call. Thank you very much.

Ladies and gentlemen thank you for participating in today's conference this does conclude the program and you may all disconnect. Have a great day everyone.