Penn Virginia Corporation

Thank you, Jade. I would like to welcome you to Penn Virginia first quarter 2014 conference call.

I am 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 our forward-looking statements sections of the press releases issued yesterday as well as our Form 10-Q, which was filed last night.

To check these up, we continue to execute on our Eagle Ford strategy posting record oil production along with a strong cash flow and cash margins. We also as importantly continue to high grade or drilling program going forward based on our overall results to-date.

So as the sweet spot we continue find it can be further exploited as time goes on. Some of the highlights for the first quarter include production of 21,133 barrels of oil equivalent per day up 6% from the fourth quarter 2013, Eagle Ford Shale production of 15,152 barrels of oil equivalent per day, up 15% from the fourth quarter.

Oil production for the company was a record 11,955 barrels of oil per day an increase of 7% over the fourth quarter with an acceleration of production growth expected as the year progresses. Also in the first quarter our cash margins remained strong with the cash margin per barrel of oil equivalent of $54 up from $48 in the fourth quarter.

Product revenues were $70 per BOE compared to $64 per BOE in the fourth quarter with 86% of the product revenues coming from oil and NGLs. Lease operating expenses decreased to $5.47 per BOE for $5.74 per BOE, gathering processing and transportation expenses decreased to $1.56 per BOE from a $1.76 per BOE.

Recurring general and administrative expenses decreased to $5.21 per BOE from $5.93 per BOE and adjusted EBITDAX was $94 million up 11% from $84 million in the fourth quarter and above our expectations. During the first quarter we increased our Eagle Ford lease position to approximately 125,300 gross and 85,900 net acres.

We added approximately 6,400 net acres in Eagle Ford at an average cost of approximately $3,000 per acre. We continue our aggressive Eagle Ford leasing effort at these attractive acquisition costs as we march toward our minimum 100,000 acre position that we communicated in the past.

We now estimate that we have the remaining drilling inventory of approximately 1,510, drilling locations of 34% increase from the 1,125 locations we previously have communicated. This is based on our ongoing leasing effort, the positive results of our [Darst] based drilling program and now the encouraging result of the recent Welhausen completion in Upper Eagle Ford.

Of this total, 1,035 of these locations are Lower Eagle Ford locations and 475 are Upper Eagle Ford locations. This new estimate does not currently assume any overlapping inventory from the Upper and Lower Eagle Ford intervals which may represent as many as 400 additional locations on existing acreage if we confirm over time that in fact the Upper and Lower are separate reservoirs.

We provided in our press release the details of our initial results from our Welhausen pad located in the southeastern part of our acreage in Lavaca County. We drilled an Upper and Lower Eagle Ford side by side and completed this on accordingly with the well Welhausen B completed in the Lower and the A well completed in the Upper.

We are very pleased by the initial results of these based on the initial production rates and pressures, a case to be made that they are acting like separate reservoirs and not in communication. But additional time and production history will be necessary to confirm this hypothesis.

The initial production rate in the press release from the Upper was 2,165 barrels of oil equivalent per day with the very high flowing pressure. The adjacent Lower tested at 1,536 barrels of oil equivalent per day and it also had a very high flowing pressure.

In addition, we have recently completed and brought online the Martinsen number 2 well, a third of a test well, approximately 2 miles from the north of Welhausen pad. John Brooks will give you some more detail on all these wells in a few minutes.

As already mentioned, longer term testing will be necessary to fully understand the upside associate with the Upper Eagle Ford, but we remain very positive about the play and that it could contribute significantly to overall production reserve growth over time. At this time, we have not adjusted our drilling program in order to take into account which at this time is considered excellent news about the Upper Eagle Ford Shale.

This may in fact occur as the year progresses, so as always we will drill the best opportunities in front of us. Through March 31, we have spent $37 million for leasehold acquisitions.

As our ongoing leasing activity remains successful, we are increasing our leasing capital expansion guidance for the year about $13 million to $20 million. Otherwise our previously reported guidance remains unchanged.

As we have disclosed in the past, we sold Eagle Ford Shale natural gas gathering assets for total price of approximately $100 million, $96 million net to our interest. Currently we have 3 other divestiture processes underway including our assets in Mississippi, Oklahoma and [rest] to build a no gathering system for our Eagle Ford Shale operations.

We have received bids on all 3, are currently evaluating and negotiating with potential buyers, and will announce any transactions if and when any agreements have been signed. This is consistent with our commitment to actively manage our portfolio and divest of our non-core assets to fund our ongoing operations in our most promising asset which of course is Eagle Ford.

To summarize it is clear that we continue to operationally execute on our strategy to build value in Eagle Ford, not only by drilling excellent wells and converting PUDs, [plays and prospects] to PDPs but also by continuing to expand our Eagle Ford leasehold position. A fairly straight forward statistics points out our growth and value.

If you buy an Eagle Ford acre for about $3,500, drill it with a $9.6 million well that acre net of investment is now worth anywhere from $80,000 per acre to $100,000 per acre depending on spacing. I think you would consider that a very attractive arbitrage.

And at this time I’d like to turn the phone call to John Brooks so he can give you some additional operational detail for the first quarter.

Thank you, Baird and good morning. For 18 wells that we turned inline in the first quarter of 2014, our average rates were 1,080 barrels of oil per day and 2,004 Mcf per day or a combined 1,415 BOE per day.

So, our well results continue to be strong. Our average well cost came in at a little over a $9 million with an average of 24.6 frac stages per well, which given our mix of mostly three stream wells deposited performance marker and continuing to this total well cost.

As we stated, Penn Virginia is running six rigs in the Eagle Ford. Little technical, we're actually running seven rigs counting the smaller spudder rig that is used to preset surface casing on the pads for the big rigs.

As we've transitioned almost completely to pad drilling, we've developed a strong inventory of wells to complete. As of March 31, we had 19 wells completing or waiting on completion as shown in the release.

Currently though, we have 10 wells flowing back from recent fracs, five being completed and another eight waiting on completion. So, we're making progress and getting caught up on our completion.

Our stimulation costs are running about $120,000 to $125,000 per stage and we continue to ramp up total sand volumes to roughly 1,500 pounds of profit for lateral foot. We continue to make real progress and being efficient and productive operator only drilling five, the aforementioned spudder rigs which presets surface casing for our big rigs saves us an estimated $70,000 and 56 hours of big rig ton per well.

The positive effects of this cycle time compression have yet to be fully realized, but we should start seeing the benefits roll through later in the second quarter and beyond. Additionally in China, which requires three strings of casing we further optimized our walking rigs to backset intermediate casing on the preset surface casing.

And then drilled and cased the laterals without having to repeatedly lay down and pick-up drill pipe, which saves us on average an estimated $46,000 and 14 hours per well. Another recent development where we've improved on our costs is in our drilling mud.

Penn Virginia now provides its own drilling fluids and fluid engineering services on five of our six big rigs on average running our own mud and in effect buying mud products wholesales saves us about 57,000 per well or equivalent to about 20%. Now, I'd also like to bring you up-to-date on our upper Eagle Ford delineation results so far.

And let me start by saying that we've established at the effort Eagle Ford works that works very well. We are still evaluating whether it is a separate reservoir from the lower Eagle Ford, but we are encouraged by recent results.

Our first upper Eagle Ford well, the (inaudible) number 1H was completed last bring, we'll relatively short lateral 4,200 feet and 17 stages and that IP at about 1,200 BOE per day and has produced 96,000 BOE in 12 months. It was drilled as a single well in this unit with no other unit by production.

And at year-end 2013 it was estimated to have an EUR in excess of 390 in BOE. So following up on that, our most recent test is our well housing unit, which is our deepest down deep test of the Eagle Ford in Lavaca County and lies to the Southeast of our historical (inaudible) development.

The Eagle Ford occurs between 12,500 and 13,000 foot PVD at this unit. And to our knowledge there are no other Eagle Ford completions in close proximity with this pad.

The Welhausen 2 well pad was drilled and completed with the Welhausen A2 testing the upper Eagle Ford and the Welhausen B1 completed in our traditional lower Eagle Ford landing zone. They were each drilled 330 feet away from the unit line which was straddled by the two wellbores so they were a total of 660 feet apart.

The A2 completion, the upper Eagle Ford test consisted of a 6,487 foot lateral with 26 stages treated with 9.9 million pounds of proppant for an average of 1,526 pounds per foot of lateral. The B1 completion, the lower Eagle Ford test consisted of a 5,905 foot laterals with 26 stages treated with 7.9 million pounds of proppant for an average of 1,337 pounds per foot of lateral.

Following the release of the frac equipment, coil tubing was used to drill out the plugs and for the primary cleanup procedures. The plugs in the B1 were all drilled out.

On the A2, the last eight plugs towards the total of the lateral were not initially drilled out. The wells returned in line to test equipment on March 20, with first gas sales on March 21st.

The 24 hours rates for the two wells since then are as follows: In the Welhausen A2, we’ve had 1,086 barrels of oil per day and 6,475 Mcf per day for 2,165 BOE per day with 595 barrels of water per day at 4,600 PSI on the 2,264’s choke. The Welhausen B1 in the lower Eagle Ford tested at 807 barrels of oil per day, 4,372 Mcf per day with a combined rate of 1,536 BOE per day at 879 barrels of water per day, 4,372 PSI on a 2,060 force.

Both wells required secondary clean out operations and during that secondary clean out operations we were also able to drill out the remaining eight plugs on the A2 upper Eagle Ford well allowing us stimulate the stages to then contribute to well bore. Both wells were returned to production on May 7th and rates on the A2 reflect higher production performance following the drill out of its remaining plugs in the secondary clean out operation.

Oil gravity for both wells uncorrected for temperatures is 55 degrees API corrected for temperatures 51 and 53. The GORs are 5,962 Scf per barrel for the upper Eagle Ford test and 5,418 Scf per barrel for the lower Eagle Ford.

And although we are seeing higher gravity and higher GORs, it appears that we are still in the volatile oil window. We have approximately 94% working interest in the Welhausen unit in these two wells.

Our next upper Eagle Ford test is on our Martinsen pad where we drilled the Martinsen #2H and 3H. The #2 well was drilled and completed in the upper Eagle Ford and is at 400 foot direct offset to our Martinsen #1 which is one of our best lower Eagle Ford wells.

The Martinsen #1 IP at 1,878 BOE per day in March 2013 and its cumulative production of over 101.8 million barrels of oil and 381 in MCF of gas all over 165 MBoe in the last 13 months. The Martinsen #3 was drilled and completed in the lower Eagle Ford and was another 400 foot direct offset to the #2 well and therefore 800 feet away from the Martinsen #1, the original well in the unit.

The Martinsen #2 has a lateral of 5,891 feet and 27 stages and frac for 10 million tons of proppant for an average of 1,700 pounds per foot of lateral. And Martinsen #3A has a 4,462 foot lateral and 21 stages and those frac for 6 million pounds of proppant for an average of 1,336 pounds per foot of lateral.

Those have been cleaned out having the plugs drilled and time to test. And it’s early in the flow back stage and both of those continue to clean up, but the results appear to point toward the upper Eagle Ford behaving independently or the lower Eagle Ford as the pressures in the upper Eagle Ford are about 2000 PSI higher.

We have an approximate 94% working interest in the Martinsen unit. So to summarize our upper Eagle Ford results so far, we have one well (inaudible) our initial upper Eagle Ford well drilled by itself in a new unit.

Two wells drilled 660 feet apart in a new unit with one in the upper and one in the lower and another upper Eagle Ford well drilled between mature lower Eagle Ford well and a new lower Eagle Ford well. In all cases the upper Eagle Ford has worked and has demonstrated that it can yield IPs with the high-end of all our Eagle Ford activity.

Determining to that is a separate reservoir from the lower Eagle Ford will take more test and additional time, but again we are encouraged by our most recent testing. Later this year we plan to have another test in our RBK unit, preliminary claims planned for RBK unit to be a four well pad with two wells in the upper Eagle Ford and two wells in the lower Eagle Ford and staggered offsets Chevron pattern with each lateral spaced 400 feet apart and plain view.

Based on these positive results in the upper Eagle Ford, we've added new locations in our drilling toward for the play, since we have not yet conclusively determined whether or not to act separate reservoirs, we haven't yet counted any locations that would overlap with lower Eagle Ford locations even though we do have some results in that regard. Out total Eagle Ford location inventory now stands at approximately 1,500 locations with about 470 of those in the other Eagle Ford.

Moving on to other recent developments on our Rock Creek Ranch wide pad, we recently drilled and completed four wells; the Rock Creek Ranch wide 1H, 2H, 3H and 4H. This is in our joint venture with Maritime in Gonzalez County.

All wells are drilled and completed in the lower Eagle Ford. The 1H has 7,055 foot lateral, 32 stages and was frac with 10.8 million pounds of proppant.

The 2H has 6,357 foot lateral and 29 stages and was frac with 9.8 million pounds of proppant. And 3H has 7,202 foot lateral and 33 stages and was frac with 10.8 million pounds of proppant.

And the 4H has 6,809 foot lateral and 31 stages and was frac with 10.4 million pounds of proppant. Proppant volumes for these four well pad averaged a little over 1,500 pounds per foot of lateral.

For the sake of comparison, we drilled out all the plugs on these four well pad with a workover rig and joined a pipe as opposed to to coil tubing. It took a little bit longer, but we got all the plugs drilled out for the higher degree of mechanical efficiency of coil.

The costs may tend slightly higher, but the joined pipe uses a higher degree of confidence in getting all the good plugs drilled out and wells with longer lateral. We have not yet IP these wells since it's early and are cleaning up, but the four well pad as a total is making about 5,000 BOE per day with 88% of that oil.

We have in approximate 47% working interest in the Rock Creek Ranch unit. That concludes my operational update.

And at this time I'll turn it over to our CFO, Steve Hartman.

Okay. Thanks John and good morning.

I'll start with the comparison of our first quarter financial results to our fourth quarter 2013 results. Total revenue for the quarter was $189.9 million; we realized a $68 million gain on the sale of our natural gas gathering system which closed in January.

$56.8 million of that gain is recognized as a gain of sale this quarter. The remaining gain will be amortized into other revenue over the next 25 years.

We received net proceeds of $96 million from $100 million sale price. Product revenues for the quarter were $133.2 million or $70.01 per BOE or 14% increased over the fourth quarter.

Adjusted EBITDAX, a non-GAAP measure reconciled on page nine of the release was $93.8 million, 11% higher than the $84.4 million reported in the previous quarter. Direct operating expenses excluding share-based compensation were $30.6 million or $16.08 per BOE compared to $27.8 million or $15.09 per BOE in the previous quarter.

In general, our expenses were better than anticipated. Lease operating expense was lower at $5.47 per barrel compared to $5.74 per barrel last quarter.

Gathering processing and transportation expense was lower at $1.56 per barrel compared to $1.76 per barrel. But decreases in LOE and gathering expense were particularly noteworthy because our new Eagle Ford gathering and gas lift agreement went into effect this quarter.

Recurring G&A expense was also lower at $9.9 million or $5.21 per barrel compared to $10.9 million or $5.93 per barrel last quarter. These decreases were offset by a quarter-over-quarter increase in ad valorem tax, we recognized a $3.6 million credit in the fourth quarter and with that credit normalized out our direct operating expenses were improved this quarter.

Capital expenditures for the quarter were $182 million compared to $150 million in the fourth quarter. The increase is primarily due to drilling and completion costs which were $135 million compared with $104 million in the previous quarter.

However, this is lower than we expected for the first quarter, consistent with the higher number of wells waiting on completion. As John mentioned, we expect we’ll catch up the completions in the second quarter.

Leasehold acquisition was $37 million for the quarter compared with $40 million in the previous quarter. Cash margin per BOE as defined in our earnings release was $53.93 per BOE compared to $48.48 last quarter.

Improvement in our cash margin per barrel continues to be driven by the strong profitability of Eagle Ford program. Our cash margin per barrel in Eagle Ford excluding allocated G&A was about $72 in the first quarter.

Our adjusted net loss attributable to common shareholders was $7.9 million or $0.12 per share compared to $6.7 million or $0.10 per share in the fourth quarter. The primary driver for the higher than anticipated loss is our share-based compensation expense specifically the liability classified awards which were $5.9 million in the first quarter.

Excluding the share-based compensation, our adjusted net loss is $0.06 per share. The liability classified awards are the performance-based restricted stock units described in our proxy statement.

Recognizing this expense is similar to a mark-to-market type of calculation. The value of these units fluctuates as a function of our stock price and our performance relative to our peer group.

In this case, the higher than expected valuation increase was driven by depreciation in our stock price of the quarter starting at $9.43 per share and ending the quarter at $17.49 per share. There has been no cash paid out to-date on these awards and no cash will be paid out in 2014, the first testing date is in February 2015.

Moving on to capital resources and liquidity, at quarter end, we had $190 million outstanding on our credit facility and $10 million of cash on hand. Our borrowing base at quarter end was $425 million.

We recently completed our spring redetermination. Our borrowing base is now $475 million which is $50 million higher than our borrowing base determined last fall.

Our next borrowing base redetermination will be in October later this year. Our leverage at quarter end was 3.6 times; total debt to pro forma adjusted EBITDAX compared to our leverage at year end which was 3.7 times and to our credit facility covenant set at 4.5 times.

Pro forma adjusted EBITDAX at quarter end for the trailing 12 months period as defined in our credit agreement was $353 million which is higher than the $342.4 million we recorded at year end. Now on to our 2014 guidance update which is detailed on page 10 of the release.

Our guidance does not include the potential sell of any non-core assets. If and when we sell these assets, we will update guidance.

As Baird mentioned, we are raising our CapEx guidance by $13 million to $20 million to $595 million to $653 million based on the success of our leasing activity. We are reaffirming our drilling and completion capital at $510 million to $540 million to fund the fixed rate program.

We are reaffirming our production guidance at 9.1 million to 9.8 million barrels of oil equivalent. Although our first quarter production was slightly below our forecast, we think we’ll catch up the production by the third and fourth quarter as we bring on line the wells that have been waiting our completion.

These wells are in our most productive areas, so we expect the sharp production increase toward the end of the second quarter and into the third quarter. We are reaffirming our operating expenses and G&A at their current levels with the exception of share based compensation.

We are increasing that guidance to reflect the higher liability based share valuation. Adjusted EBITDAX is also reaffirmed at $440 million to $485 million.

We assume a $90 WTI price, a $5 basis differential for LOS and $2 off of WTI or $88 and the realized price for our Eagle Ford oil production. To protect cash flows, we have 67% of our oil production hedged as a percentage of the midpoint of guidance for the rest of 2014 at a weighted average floor price of $92.94 per barrel.

For our program funding using the midpoint of guidance, we expect our 2014 outspend will be around $265 million, $96 million of that is already been funded through the gas gathering system sale that closed in January. We expect the remaining $170 million to be substantially funded by the sale of our non-core assets, potential proceeds from our oil gathering system rights that is currently in market and the final cash settlement from Magnum Hunter related to our Eagle Ford asset acquisition last year.

That final cash settlement is in arbitration, we expect the decision from the arbitrator by the end of the quarter. Magnum Hunter has indicated that we generally agree on a minimum of $26.5 million.

We believe it’s higher but that will be decided in the arbitration. Any remaining outspend will be funded on our credit facility.

At quarter end we had a $100 million outstanding. Our current guidance provides for $315 million to $375 million drawn on the credit facility at year end.

And as a reminder this does not include any of the proceeds from asset sales, but it does include the Magnum Hunter final settlement that we agree on. Under our current borrowing base of $475 million, we would expect to end the year with a $100 million to $150 million of liquidity absent any of these asset sales.

However, we do have our fall redetermination in October where we expect to increase our borrowing base as we have the last few times. If we receive a $50 million increase which has been now received in the last two redeterminations, we would have year-end liquidity of a $150 million to $210 million even without any asset sales.

That concludes financial results and guidance.

Alright, thanks John and Steve. Kate, at this time we are ready to take any questions.

Good morning guys and great color. John I guess and Baird for you either John, just now with obviously the success of the separate Eagle Ford, just wondering how to [attack] at your thoughts as far as a couple of things there as far as number one, just the spacing you perceive.

I know John you went into that a little bit. And then secondly, how do you take that from sort of regions, I mean is it you just kind of blanket I guess each area or you are more delineate that, I know you talked about this part and sort of the next one that you'll do, I'm just wondering sort of going forward how you back that?

I'll take a stab at first Neal and I’ll let John add anything if he wants to. I think at this point in time, we'll still continue to test the extensiveness of the upper Eagle Ford in the results by that testing.

As the year progresses, us having time to sit back and look at the well Welhausen well. Now there could be a case we may to swap out some Lower Eagle Ford for some Upper Eagle Ford.

I see no reason at this time that spacing wouldn't be any different than what we experienced in the lower Eagle Ford anywhere from 400 to 500 feet or 50 to 60 acre spacing. I would see no reason why we would adjust that spacing for the upper versus lower.

So, but at this point in time, we're going to sit back and what we've done, look at production history, continue to gain confidence at which time again our motive is to go ahead and drill the best wells we can with the best economics and make some adjustments as time goes on. John, do you have anything else to say about that?

Just to add that the RBK unit that we plan on drilling later in the year, we'll test two lower and two upper in any offset staggered pattern and we hope to gain some more information from that test.

Got it, thanks guys. And then just one follow-up as far as now with the additional location, I know you mentioned I think what was the 1 spudder rig in addition to the other 6; will you add -- your thoughts about even that in another spudder rig as it makes sense to do that or just more maybe another 1 or 2 larger rigs.

So, 2 questions are just overall rig count, your thoughts there Baird on how that might change given the additional locations? And then secondly, does it make sense to go with additional spudder rigs, is it cheaper to sort of try that processes versus just having additional larger rigs?

Well, again I'll let John to call. But I think one spudder rig we have is okay with the 6 big rigs as we continue to gain efficiencies on the drilling side.

John mentioned in Lavaca County of drilling all the intermediate holes setting intermediate casing and then walking back and drilling the production holes in that rig. Let’s say it’s time.

So we think we can actually drill more wells with the current number of rigs we have. As far as accelerating activities this time we have no plans to do so, but it is something we continue to look and especially with an increase in inventory because of the Upper is something we will take into account more seriously especially take into account the sale of assets.

Very good. Thank you all.

All right, thank you.

Yes, good morning.

Hey.

So, can you give us sense of what productions looking like right now obviously there is a lot of well that were I guess back-end loaded and then certainly we need a pretty good surge of oil production coming through the rest of the year to kind of hit the full year target. Can you kind of give us a sense of where we’re sitting at right now or kind of the volume metric ramp through the year for oil?

For March we averaged about 22,000 barrels a day equivalent net. I don’t have a current churn figure but with the recent churn into the Welhausen wells with the recent churn into the [whacked] wells that John just mentioned that we’re making about 5,000 barrels a day equivalent gross on a net basis we probably have 35% of that.

So that’s another 1,000 to 1,500 barrels a day. I don’t have a good figure right now, but I would expect for the second quarter we should be averaging around 24,000 barrels a day equivalent, if not more because of the churn-ins the accelerated churn-ins.

Okay. And the oil cut done on average should really start to climb now with these latest wells?

It sounds like the pad that you are (inaudible) with Marathon had some pretty high oil cuts, is that going to continue with some additional drilling for the year?

Well we haven’t mix of wells. I mean the we clearly got [gasier] with the Wellhausen, but we should be able to maintain a mix between where we are drilling oilier wells and gaser wells where as our historical mix ought to be about the same.

Okay, understood. And then one other question, obviously you talked about if you can have the Eagle Ford, the Upper and Lower Eagle Fords coexisted to put another 400 potential locations, bigger picture when you look at areas where you have yet to really test the Upper Eagle Ford and quite frankly I think some of the acreage where you had identified some of even Lower Eagle Ford what could that 1,500 drilling location count kind of move to overtime?

Well, Scott if you add the other 400 locations we talked about were both the Upper and the Lower coexist, you get to 1,900. We continue to pick up acreage expect to get to the 100,000 acre bogie, close to the 100,000 acre bogie by the end of the year.

So that’s another 14,000 net acres, you do the spacing on that that probably adds another 150 to 200 locations with that additional lease act. So I mean we should be able to do something we feel confident about the Upper and Lower being separated I would expect that 1,500 number to go to north 2,000 toward the end of the year beginning in next year.

Yes. And I guess specifically Baird on the acreage that you all have right now and maybe I am incorrect on this but if you correct me but there is some areas I think you more than north where -- north and a little bit to the west where you get to assign some Upper Eagle Ford in some parts of the recent acreage acquisitions you have made to the East, I don’t think have really much identified for Eagle Ford oil, is that a fair statement?

Yes, it is. As you go to the North and East, the Lower becomes less perspective and the Upper becomes perspective.

We need to get out here and drill some test wells overtime as we continue to sure up our acreage position and increase the size of the drilling units, whether we get that done all this year or whether just slots over in the 2015 is yet to be determined,. But the whole Upper Eagle Ford at least based on the results of the Wellhausen and maybe the Martinsen and the fire stick, it just becomes the different play with as probably an extensive running room yet to be defined exactly where that is, but it just makes this whole leasehold position big and perspectively a lot bigger basin what we know and what we are learning.

Okay. So that gets delineator over the next year, year and a half, okay?

I think so. I mean the acreage that we have in the North.

We continue to acquire acreage up there that’s adjacent to what we already have just to make the units larger, so to give us more room to drill longer laterals. So that will be done throughout the remainder of this year and probably not test that acreage probably till 2015 if I had to guess.

Understood thanks.

Thank you.

Hey, good morning, I was curious if you are seeing anything, just for in the [Rockothology] forum from the Upper and Lower, I understand your sample set, isn’t that big yet?

John, I want you to take step and have please?

Sure. I mean methodology on the Upper Eagle Ford by definition we are calling it a, moral so it’s about a 50% carbonate.

So, we do have that distinction versus the Lower Eagle Ford has a much Lower percentage of carbonate. So, I would say that's the primary distinguishing with a logic distinction.

Yes. Do you think any of that sort of feet influences into what you might see in the decline rate for Upper and Lower or the IP of Upper and Lower, just trying to get a sense how much of it is just enhanced perm in the Upper, which shows up first and depletes quicker or something of that nature.

Well, ultimately we're putting away a lot more sand, you might have noticed, we're able to pump a lot more send in those Upper Eagle Ford completions. So, we're getting a what we believe is a very high stimulated rock volume, which would go beyond the primary perm and porosity that we encountered in the near well board.

So, I think that it only helps you extend your fracture system beyond what you normally would by having the relatively higher perm and porosity that you encounter.

Okay. And you didn’t lose anything in [Pearsall], I think you mentioned in the Martinsen that the Upper had higher pressure than the Lower and....

3,000 yes.

Yes. And what sort of explanation, was it sort of seal in the Upper in generating that sort of thing?

Well, I would the easiest explanation that I can come up with as you said it's not been influenced by the Lower Eagle Ford well 400 feet away.

And is that 400 vertical displacement there or was that the….

Lateral.

Lateral. What is the vertical displacement here?

On the order 100 feet to 150 feet.

Okay.

And (inaudible) throughout the field, it may not be specific to the Martinsen pad. But 100 to 153 feet is generally the vertical separation between the two.

Okay. And a final one for me.

The flat chalk, how did the [GORs] performed overtime, were they fairly stable of rising and falling.

On the fire stick?

Yes.

Yes, I think it rose a little bit, but it was nothing markedly out of the ordinary. I mean most of these wells will have a little bit increase in their GOR overtime but there was nothing remarkable about it.

Great. Well congratulations.

Thank you.

Thank you.

Hi, good morning, thanks. John you mentioned this, but in your previous slides, you have had a nice trend in quarterly well cost but total and in completion cost per frac stage.

Do you have those numbers for the first quarter?

No, I think the number I quoted was roughly $9 million a little over that and I think we had down to was it 26 stages. So I think we're right around, if I had -- doing the quick math probably around 350,000 per frac stage.

Okay.

[In churn coal].

Okay. In terms of the two Wellhausen wells total cost, notice any difference between the Upper and Lower Eagle Ford wells?

Well both those wells cost more than a typical well, so it’s the upsize to the wellbore we set 9 and 5 rates is our intermediate stream. Our partner in the area at the time GeoSouthern which is now Devon had encountered some drilling difficulties when we took the farm out.

So to overcome whatever drilling challenges that we might encounter we upsize the wellbore in the initial test. So I think going forward we’ll have a more typical wellbore geometry.

But to get to your question the difference between the two was not -- no real noticeable difference other than we learned a lot from drilling the first one and it helped us drill the second one better primarily because we’re in a new area that is we didn’t have a whole lot of bit records at that depth in temperature.

Okay. And I know it’s early in the game but the 475 Upper Eagle Ford locations you have an inventory now, anyway to break that down at this stage where you think how many might be in this gaser area with the Welhausen well exhibited versus your historic oilier Lower Eagle Ford wells?

Yes, I think it’s going to be on the trend that would be on strike with that running from the Southwest to the Northeast.

Got it.

So, Steve you’re saying it ought to be about the same probably is what our expectations would be.

Okay. That’s it for me.

Thank you guys.

Thanks, good morning guys.

Good morning.

Few quick questions, just on the Selma Chalk and the Oklahoma assets that you have out there for sale it sounds like you got bits indices. So it’s not something if it happens it will happen in the coming quarter and can you remind us how much production is associated with that?

To answer the first question if this is going to happen it would happen this quarter, it may happen late this quarter i.e. June but it may move over into early July.

But our expectations it’s going to be whatever we get done, we’ll get done this quarter. As far as production, we’re talking about 1,900 barrels a day equivalent, each one would be about that number.

And with the gas cut is on that production?

Well in Mississippi it’s almost 100% gas in Oklahoma if you took it back 35% to 40% of that would be well head and NGLs with the remainder being dry gas.

Okay, sounds good. And then on the acreage that you have been adding, I mean it’s been great the way you have been able to add at a 3,000 an acre.

Is that acreage cost starting to move up just with the Upper Eagle Ford test well that have coming up from you and from the rest of the industry?

Well I would expect it probably will start creeping up, I mean it’s hard to keep a good well secret. And I would imagine this will start gaining some people’s attention.

But as of today there $3,500 an acre is a number that we are success with. But I can’t imagine it may start to creep up.

And as most of the acreage Baird that you are adding is it just acreage that’s expired from the previous owner and then you are able to lease it?

There are some soft leases we may put in place before it expires but in most of cases this is brand new acreage.

Okay. And then just final question on the Wellhausen well, can you just provide some color on how the production is looking today after that second May 7th clean-out?

John.

I can tell you the test rates I saw this morning, we still got flow back crews out there. We filed W-2s for both wells yesterday; today’s production is higher than yesterday.

So it’s continuing to -- it’s hanging in there, and a slight improvement but we’ve kind of just held that [choke] works out but we may have one more choke size open it but we are going to be [doing] with it, and try to understand and absorb the longer return production of this before we get really aggressive with opening the choke.

The GOR is holding in the same as your initial reported GOR?

Yes.

Okay, thanks.

Good morning.

Hey, Welles.

Most of mine have been answered but I’m having a trouble [HPPs] starting in the RBK pack, can you tell me where is that going to be?

Yes, that’s going to be probably about right smack dab in the middle of our Shiner acreage.

Okay, so moving up dip little bit.

IT will be up bit from the Welhausen and probably on strike with our Blonde which was one of (inaudible) well, it will be just East of there but in the center of our Shiner acreage.

Okay, great, that’s perfect. And then just one more one and it’s probably just fiscal noise but it looked like the 30 day rates from your Eagle Ford program were a little bit lower quarter-over-quarter.

Am I right that that is probably just noise or did you guys move around to some different parts of the acreage?

Well, there are some shallow wells in there that we drilled in our legacy acreage up in Cortez, the Millers and the Cusacks, specifically, the Cusacks were 2 wells drilled in between on a down space basis, between 2 material wells that had already produced 100,000 barrels likewise the Millers were offsetting some mature producers. And as we go to a lot of these pad wells we’re offsetting existing production.

So, I think the lesson learned is that the earlier down space is better than off yard.

And would that -- I mean obviously if you're going to move to kind of dual development of Upper, Lower sooner is better especially with that piece of infield. But what -- how long and I know it's hard out to pin out, but how long would you guys want to see [fast] in the Welhausen and the Martinsen and even RBK pad, before you have the kind of confidence to move that into a development type program?

I think we have the confidence to move this into development program now. But with the 6 rigs that we've got in drilling schedule, we’ve got -- there is just constraints on where we drill to meet our obligations elsewhere.

But we have the confidence in drilling those wells.

Okay, perfect. Thank you so much.

Thank you.

Hi, good morning guys.

Hi Adam.

If I look at your recent slide presentation on the Upper Eagle Ford, it looks like the fairway extends on into Fayette County, and there is a couple of sweet spots up there. I'm just wondering are you guys leasing up in Fayette and do you think it's prospective to the Northeast?

John?

We do think it is perspective up there, but I think a lot of that acreage is currently held by others. So, we are focusing in the areas that are most accretive to our existing leasehold position where we can block up existing acreage.

We've got between Gonzalez and Lavaca County, we think we've got ample room to grow that and opportunity in Fayette County at some point comes that's something to review at that time. But I think there is players up there in Fayette County that we would have to hop over and take additional geologic risk to get any meaningful size of available acreage.

Okay. And I think the rest of my questions have been answered.

Thank you.

Alright. Thank you.

Thanks, good morning everyone. John, going back to the question on the decrease in say 30 day rate or even the rate per stage for the latest Eagle Ford wells versus say the prior group.

Like wells to like wells evenly spaced apart, I mean how do you look at the performance there versus say what you saw in the last two quarters throwing out say some of the wells on the tighter spacing or on the legacy acreage?

Well, there is handful that we also had some mechanical issues on. We didn't get all of the stages fraced or didn't get them all drilled out.

We had a casing issue on one of them. So, there is a degree of variation that is always going to occur, hopefully the mechanical issues we've addressed by changing our casing design.

We've gone through a [beefered] casing with the better coupling and basically changed out our [tubular] design to help overcome some of those issues. And also some of the longer laterals that we’ve seen, we haven’t always been able to get them drilled out.

So if you frac 32 but you can only open up 29, that creates an issue. Likewise if you plan for 28 but due to a casing issue, you only get 23 away, that creates an issue.

So, we’ve had a handful of those in these most recent set of wells in addition to the shallower wells. And the mechanical issues are something that we hope we’ve got behind us.

But it’s something that we just continued to evolve the drilling and completion design to deal with the challenges that they present.

Okay. No change in your outlook going EUR estimates for Gonzales and Lavaca correct?

No.

Hey Richard, just to add on what John said, I mean if you take this fairly small data set that John elaborated on, some of the mechanical issues we had, we don’t view this as something we expect longer-term. That longer-term is we continue to say we are drilling the best opportunities we can.

And it took some time after we reported like the Blonde and [Quarter] wells and Lavaca wells to get things ready to go ahead and exploit those specific areas with a more aggressive development program. So you’re going to see that development program progress further along in these better areas we’ve identified based on IP and 30 day rate.

So, it is just a quarter data set that has some noise in it, I guess probably the best to say.

Okay, thank you. That’s helpful.

And looking at -- I know it’s early, certainly early for this Welhausen well. If I remember correctly, did a third-party engineer give you 450,000 barrels for that first upper Eagle Ford well?

Well it’s drifted around, I think recently it was 350, then it went over 400, I thought it was 420 here. And now at year end it’s back down to 390.

I mean it’s not unusual for these things to drift around here for early in our history until the terminal decline rate is clearly identified. So, it’s somewhere at the end of the day, I think it’s going to be somewhere around 400; it could be north of that because I think terminal decline rate our third party engineer is using is too steep.

I mean we are using a 12% terminal decline rate on this stuff which at least based on my years of experience on recent work plays, I think that’s way too aggressive but that’s what these guys are going. And I think they do the reserves.

And if you change that 12% to 6% for instance, I can’t tell you exactly how many reserves you add but it’s mature; you don’t add a lot of present value to shed a lot of reserves.

Sure. And then just lastly, in general where is the Eagle Ford acreage that you say acquired over the past couple of months, I guess it was the 6,400 acres?

John?

Well, it’s in the area of the Welhausen and on strike with that to the Northeast.

Okay, that’s all from me. Thank you.

Hey guys, couple of housekeeping questions. One on your revolver, I know your borrowing rates went up to 475, did lender commitments also go up to that level or is it still at 400?

We said lender commitments up to 450.

450. Okay, great.

And just secondly operationally with regards to the -- I know you will be partially leasing in some areas, just wanted some thoughts on the Hunt acreage in that JV. Are you actually letting any acreage go at this point?

John?

No, we are not letting any acreage go at this point; all that acreage has been HDT. The 6,500 acres, net acreage that Hunt operates; they have HDT all that acreage and changed their drilling in the fourth quarter of last year to the other parts of their Eagle Ford play.

So, we don’t anticipate any acreage in that area expiring due to lot of activity.

Got it. And then one last one, just looking at some of the wells that you guys reported this time around, I would point out the Leal 4H and I think the Pavlicek 5H and Berger-Simper 1H, all of them look like the 30-day IPs came in at less than 50% of the 24 hour IP.

And I was just wondering if there were any specific issues relating to those wells and anything, any color you can provide on that will be helpful? Thank you.

[Jerry] on the Leal, one thing I will mention is those two wells were our tightest spacing test, those wells were drilled at 375 apart. On the Leal #4, we had a chasing issue and we did not get five of our 28 planned stages frac.

So we did not get all of that get away if we’d like to. On the Pavlicek as well, those were down spaced wind field wells.

In one of them we had a 20 frac stages. So once again, I'd say the lesson learned here for us is down space earlier is better.

Got it. And do you still think you need sort of the 40 acre down spacing, how many of those steps have you gotten done and if that's still the expectation that 40 acres is going to work?

Yes. I think it's going to be in the 40 to 50 acre depending on the actual lateral link, that’s still our current plan of development.

Great, thanks guys.

Thank you.

Good morning gentlemen.

Hi Gail.

A quick curiosity regarding optimal lateral link, you guys -- have you done a mixture of shorter and longer laterals and I'm just curious if you guys have an idea of what do you think is going to be kind of that best lateral link going forward or if you are still kind of in the testing phase?

Right now, we are constraining to the most part our laterals to a [computable] lateral link to 7,500 feet. There will be occasionally one that will exceed that mainly because of a unit configuration, geologic issue or something that would prevent it from getting with another wellbore that we’ll reach out and drill a little bit deeper.

But to the most part, I think going forward our plan is to constrain our lateral link to 7,500 feet attributable lateral.

Okay, great. And then just looking at in Lavaca County the acreage, the far East acreage, wonder if you guys have any plans to touch that parts of further East to the Lavaca in ‘14 or is that kind of ‘15 and beyond story?

I think that's going to be ‘15 and beyond story. We've got a bit of acreage that we've added in Northern and Eastern Lavaca.

Some of it is nice and blocky, the rest of it we are trying to grow those into larger drilling units. We don't want to just have 100, 200 acre drilling units out there, we strive to build 600, 700 acre drilling unit.

So, I would say that would be something beyond this year's drilling schedule as we've got this year's drilling schedule fairly firmed up.

Okay. Thank you very much.

Yes. Hey, good morning everyone.

Baird, you said that by the end of the year you could be up to about 2,000 locations which is obviously a huge number and it's not unreasonable to expect a step change in CapEx to -- you’re kind of a victim of your own success with that location count. So can you just talk about some of the options respond to a significantly larger program as you see it now?

Well, first of which is a sale assets as Steve elaborated on, take weeks (inaudible) and see how we do there. We can always bring a partner in.

As far for to the acreage that maybe conditional to brining the partner in if we want to retch it up activity. And lastly capital markets are always an option, we just have to -- accelerating the drilling activity to the value point to the capital markets both debt and equity.

So it's just all those options are on the table at this time yet to be determined exactly what we may do. But clearly with these many things to do in ‘15 plus year inventory it would make sense for us to figure out to get way with accelerated drilling activity.

Yes, great. And on that RBK pad what exactly is the timing of that pad?

I am wondering whether you’re going to -- how many months of production you’ll have before your 2015 CapEx is finalized?

RBK we should start drilling on that in the third quarter and we would probably have first sales late this year early next year.

Okay, great. Well everything else has been answered; so congrats on the upper Eagle Ford.

Thanks Kim.

Good morning gentlemen. Good call.

On the upper Eagle Ford everyone is talking about, can I geographic kind of take a picture of this, there is a line for Welhausen and Martinsen to what will be RBKs of (inaudible). Is that line a general rough estimate of this new 475 wells you mentioned, is it like a rectangle with that being the center point, some east some west of that line or how do you describe this new upper area?

John, why don’t you answer that please?

Okay. I would say if you could imagine a teardrop with the point up and that would be up around where the (inaudible) is and then it would the upper-end of that teardrop go along the line that you mentioned or maybe a little bit of northwest of it and then rolled down to encompass the rest of our lease hole to the south and east.

Okay, down to the Welhausen?

Pass the Welhausen, yes.

Sounds good, okay great. Okay.

I appreciate it, great quarter.

All right, thank you very much.

All right, thanks Kate. I hope you could see that we are making progress.

I realize we had some noise in the first quarter, but at this point in time we certainly consider a noise and we have no reason to expect that we can’t continue to grow this thing, grow the Eagle Ford, continue to take advantage of what we think we have a huge opportunity in the upper at this point in time and really as the year progresses look forward to continue to bring you up-to-date, so with that good day.