I would like to welcome to our conference, Penn Virginia Corporation. With us from the company today for the presentation is Baird Whitehead. He is Penn Virginia’s Chairman and CEO.
Thank you, Jeff. I would like to introduce Jim Dean, our Vice President of IR is also here with me. Penn Virginia is of course a small cap onshore E&P company. Our focus over the last couple of years has been Eagle Ford Shale. We've had excellent results to-date. We've a built a sizeable position for a company our size in the Gonzales and Lavaca County areas.
At the same time, we have a principal and production position in East Texas, which is our Cotton valley and Haynesville Shale, which are both horizontal plays, the Mid-Continent with our Granite Wash and Mississippi with our Selma Chalk play, which is also gassy but horizontal.
We have made a significant transition to oil and liquids over the last couple of years, but you know, some part of the upside of this company remains within improvement in natural gas prices. The past two years have been transformational and we have diversified our portfolio towards an oil and liquids kind of portfolio.
We have had very successful drilling in the Eagle Ford Shale. We now have 53 wells on line, 48 of which are in Gonzales County, five of which are in Lavaca County and we continue to add to our Eagle Ford drilling inventory. Beginning this year, we added with about a 13000 gross [format] from a large company in Lavaca County, we have drilled six wells.
We’re completing the sixth well of the six well program. All those wells have been very, very successful and at the same time, we continue to block and tackle and add some adjacent acreage to where we already have. Our strategy has resulted in a significant increase in EBITDAX and cash operating margins. But we are focused on improving liquidity. I think we've been put in the [penalty] box as a company for any gas company or size we've had to stay focused on liquidity.
We recently saw our Appalachia assets which excludes the Marcellus Shale for $100 million and we're also cut our $10 million per year dividend. Our current borrowing base is $230 million with a $125 million of current availability.
We have reduced our CapEx program in 2012 which is 30% less than what we had in 2011 and important to us as we have some significant hedges in place. On the oil side we're 67% hedged for the second half of this year with an average price of $101 per barrel. So what are the catalysts. The catalyst for this company is staying focus on Eagle Ford and strong results in the Eagle Ford. And more importantly continue to expand our success in Lavaca County.
We've had some very impressive results today. We think we are in the right fairway and I'll show you here a map here which shows where our acreage position is. Continued increase in our oil production and oil reserves, our operating margins and cash flows and it is important to us is not only Eagle Ford, that we do think we need to diversify to some extent, we have a new ventures team in place, they will continue to look for new exploratory oil play types.
At the same time, we do have an attractive natural gas asset base that is primarily held by our production even after the Appalachia sale, but with our challenges. This is a very capital intensive industry. We have suffered as far as income associated with natural gas because we of not only the decline of our natural gas assets, because of lack of drilling, but more importantly of course is because of the decline in natural gas prices.
We continue to build financial liquidity, we have got to continue to fund our Eagle Ford Shale and the opportunities we have there and other oily exploratory drilling that we will become involved with. And more importantly as we have got to continue to expand our drilling inventory, I think we somewhat again get criticized for not having enough to do. I don’t necessarily agree with that, we have four to five years of things to do in Eagle Ford.
We can continue to add 4000 to 5000 acres a year in and around where we already are and are essentially replaced our 40 well program on an annual basis. So I think that we can perpetuate by drilling inventory by adding 4000 to 5,000 acres a year.
Our strategy is gas to oil transition. We have built our Eagle Ford from initially 6800 acres a few years ago up to about 25000 net acres. We have added a few thousand acres as I said early since beginning of the year. We have up to approximately 250 total well locations and this includes acreages and locations of our AMI in Lavaca County.
We have been able to grow oil and natural gas liquid production considerably. We have grown from approximately 2500 barrels in the second quarter of 2010 to almost 8800 barrels in the second quarter of 2012 or 257% increase. This is up 70% from the 5200 barrels in the second quarter for 2011. Today our oil and natural gas production is 45% of our total production whereas just a few short years ago, it was about 10% to 15% and its 86% of our product revenues today. So it is material.
We will continue to retain our gas assets for what we think will be an eventful gas price recovery. So it is included in our Haynesville Shale, our Cotton Valley and Mississippi Selma Chalk. If prices go to around $4 on the gas side, we probably would reinitiate the Cotton Valley, it is a very liquid kind of play especially in the basal part of the Cotton Valley in the southern most of acres in Harrison County Texas. So there is a play type that we could resurrect which is some modest increase in gas prices.
We have taken steps to build our financial liquidity and improve our operational focus. We sold our Appalachian assets for $100 million in July of this year. We discontinued our dividend which is at about $10 million annually which will allow us to reinvest and [essentially] doing about 12.5 Eagle Ford growth.
In 2011, we sold our Arkoma assets for $30 million. So we have retraces for as what we are focused on. We have continued to expand oil and liquids reserves in our drilling inventory. We continue to lease and expand our Eagle Ford. We just recently drilled Viola Lime prospect which is a fractured carbonate up in Jefferson County, Oklahoma. We got about 10,000 net acres in that play right now, its drilled even though we got a short lateral than we had expected but is still long enough at 1800 feet to get the prospect as to the intend right now or activity as we speak, it has been completed. We are setting a pump jack on it in order to see how it is going to do.
So we are going to continue to grow our oil and liquids production and our cash flow where the continued emphasis on Eagle Ford increasing from two rigs to three rigs in September later on this month that we were originally at three rigs beginning of this year. We cut back to two rigs for liquidity issues that we're now ready to go in and increase that to three rigs, considering the ample opportunities and great investments those kinds of wells are.
Sure it tells us a story of the company over the last couple years. In mid-2010, we implemented the strategy from a dry gas to an oil, natural gas liquid kind of company that we’ve seen decrease in gas prices but increase in oil and liquids prices and a shift to that typical market from a six-to-one value, to a 20-to-one value today.
You can look at the lower left hand corner graph. You can see what our production has done. You can see what our production has done as compared to liquids and natural gas back in mid-2010; we are roughly 15% total liquids. Today, we’re 55% liquids. If you look at the total production over that same time period, taken into consideration sale of assets, it's been essentially flat but the percent of oil and natural gas liquids is now 55% versus 45% for natural gas.
You can see in the lower right hand graph, what the revenue side has done, even though our production has essentially remained flat, we’ve gone from something that’s been 25% liquids to something now, we’re 86% liquids to natural gas component because of the decrease in pricing and because of our overall decrease in natural gas production is today only, about 14%. So, this company has changed dramatically in a short period of time.
The EBITDAX has increased significantly since mid-2010, we've go up from where it’s only about $40 million a quarter, we've increased that about 50% over about the last year. So now something is other been an access of $60 million a quarter.
Our gross operating margin for Mcfe is also improved considerably. We've got from roughly $3 per Mcfe to about $5 today and it’s strictly because of the increase in oil prices, along with our increase in oil and natural gas liquid production. So we've made a significant increase in EBITDAX in a fairly short period of time.
Next page shows where our assets are located. Our CapEx for this year of the most recent guidance is anywhere from $300 million to $325 million. You can see over 90% of that is being spent in Eagle Ford. Our 2012 production, we've given a guidance range of 37.4 Bbl’s to 39.70 Bbl’s; 47% is oil and natural gas liquids.
You can see the map as far as where our liquids or where our assets are located, you can see our Eagle Ford assets in South Texas or Mid-Continent which is primarily Granite Wash, our East Texas which is Haynesville and Cotton Valley and Mississippi Selma Chalk which is in Southern Mississippi.
Our reserves pro forma of the sale of Appalachia is almost 780 Bcfe. To talk you in more detail about our Eagle Ford, as I said earlier we've got back 25,000 net acres in Gonzales and Lavaca County today. We’re in a fairly concise area in Eastern Gonzales, Western Lavaca County where the operator in Gonzales County would have 83% working interest, where the operator in Lavaca County with a minimum of 57% working interest depending upon one of our partners decides to do.
The average IP in 30 day rates are about 1,000 barrels a day and 650 barrels a day accordingly. The Gonzales type curve is about 4,000 barrels equivalent of which 84% is well wellhead oil and 9% is natural gas liquids and 7% is residue gas post processing.
We have been focused on reducing our costs and we have been able to reduce our profit costs considerably profit costs are coming down not only because of price that they are coming down, they were also focused on using white sand in Gonzales County whereas we are using higher strength prop-in early on.
We are also buying [chemical] across direct, we are buying [gell] direct, we have been able to reduce the cost of that substantially. So in any case, we are making some progress on our drilling and completion costs. I think one of the points you remember or my people is when we report an IP, we have quite a bit of back pressure on our wells. We typically reported an IP with nothing larger than a 64 (inaudible) often times its 14 64s and most of the time in Gonzales County you will see around a 2,000 [tonnes] flowing pressure and you will see 3,000 plus in Lavaca County.
So we are holding quite a bit of back pressure on these wells. So we don’t we are not out to try to report the highest IP, it’s our intent to maximize performance of these wells and we feel holding some back pressure on these things for extended pretty time is a right thing to do.
Lavaca County has worked very well for us, it wasn’t exploratory idea when we first got into it because the overall concern you have got in Lavaca County the clay content would increase and clay content and these resource plays, shale do not necessarily go hand-in-hand.
We have not seen any deterioration in results as we got to the east. In fact, our expectations have been, we feel in most cases it has exceeded. We are also starting our [gas] basin program, we drilled a three well program in Gonzales County, fracked those three wells not simultaneously, but one after another, did not see communication, have not seen communication between those wells. So we think going forward, even though we have not drilled a lot of gas based wells to date, you will start seeing us do more of that beginning next year.
We have up to 200 drilling locations remaining on our rigs positions and that is not getting too aggressive as far where we put those locations and how many locations in this basin as well as locations and I will show you something here soon. We have dedicated rigs, we have two H&P rigs in place.
The third rig is a pioneer rig which will start at the end of this month. We also have a dedicated frac crew that is in place at least through July next year. And as I said earlier that we are going from two to three rigs. At the end of this month, all the gas gathering is in place. We have a processing agreement in place. So it is not having to sit back. Often times we have these wells from spud to turn in line in about a months time which is important of course.
So a little bit more detail as far as where acreage is? You can see it is fairly blacky, this cross edged acreage is the new AMI that we have with a major company. We have shot a 3D over our Gonzales County stuff, we will have a 3D shot over Lavaca County probably by the middle of next year.
You can see a number of our results in the right hand table, a lot of these wells have in excess of per 1000 barrels a day equivalent. There has also been some very good results in and around as most notably EOG Magnum Hunter and an important well that shows is this neighbor’s first reserve, NFR well to the east and north. This was a very positive data point and helped de-risk the eastern part of this Lavaca County acreage, which we had the most concern about getting in to this play.
Again a little bit more detail. This shows our pipeline system in blue and orange is our energy transfer pipeline system that have laid to us in all cases. We have connected Lavaca County through our Gonzales County facilities, as it goes in to that energy transfer pipeline. We have more than enough capacity dedicated to us at that plant. So we feel that we have very, very little takeaway concerns going forward.
So you can see the joint program in Lavaca County to-date shows us the six wells. The Pavlicek is the northernmost well that we’re just finishing up on the completion as we speak. The McCreary well is in next row of wells to the east. The McCreary well really is probably the best well we have drilled to date.
So in any case, we're starting to feel good about what we have on Lavaca County. I would tell you the Effenberger well is based on short term information and limited information. It's probably around a 600,000 barrel kind of well. So it's been a very, very good well but in any case, what we have seen so far in Lavaca County makes us feel good about the bulk of that acreage.
As I said earlier, I wanted to show you the number of locations we had. By track, some of this doesn’t mean a lot too. The shiner is Lavaca County. At this time we only had four wells completing. Now we have five, but you can see the total number of wells per area, you can see the gross acreage, you can see the net acreage and you can see the acreage per location. So we've not gone crazy on with a 145 acreage per well and I am putting a number of locations on our acreage. Do we think we can increase this. We do.
You know realizing that things move around over time as you can continue to drill, but we think we will continue to down space further, a lot of our down spacing is based on anywhere from 60 to 80 acre spacing at least on part of the acreage. We think that based on or some of the non-uniform parts of our acreage that we can unitize with adjacent Jason operators. It also has the same problem. In pick up locations we have now reflected in this table, but in any case again we have a lot of running room.
We think we can continue to add 4000 to 5000 acres per year which will essentially replace the 40 wells that we will drill per year. This shows we've been able to do as far as our Eagle Ford production over the last couple of years. In the first quarter of 11 we were essentially nil, almost 600000 barrels in the second quarter of 2012.
In fact we been able to increase production about 50% from the fourth quarter of 2011 to the second quarter of 2012. And 95% of these volumes are liquids and most of that of course is well crude oil. We sell most of this oil into LLS market to multiple purchasers. For the time being we're tracking this stuff out, it will be our intent to make an attempt to get these things tied into an oil pipeline through locked units. Over the next year or so we feel that, that could add $2 to $3 per barrel by doing it that way. So that will be an emphasis of us going forward, but in any case you can see what we have been able to do in Eagle Ford in a short period of time.
This is a rate of return slide versus well cost for Gonzales County, this assumes a 400,000 barrel type curve with a 1000 barrel per day IP rate and about 780 barrels a day 30-day average rate. This assumes a drilling and completion costs of anywhere from $7 million to $8 million. We feel that an average cost is about $7.5 million.
We have drilled wells less than $7 million typically at the end of being a shorter lateral kind of wells with fewer frac stages, but it is our emphasis to continue to drive those costs down. We are running entirely white sand in Gonzales County now and Lavaca County, which I will show you here soon and we continue to run strength prop-in at least in some part of the frac stage because of the depth and because of the (inaudible), but any case we feel routinely going forward about $7 million to $7.5 million is probably is a good number.
If you assume a $4 flat gas price which at the end of the day gas price doesn’t have a lot of bearing on the economics. I assume an $85 oil price, we are generating anywhere from a 33% to a 45% rate of return that being for a $7 million and $8 million drilling completion costs.
Lavaca County we see at this time, again with a caveat being, we don’t have a lot of data but at least based on what we have seen, we think that we have a 500000 barrel typical well. That’s an IP of about 1100 barrels a day, about 850 barrels a day, 30 day average. Drilling and completion costs are higher because of the -- we have to set an intermediate string of pipe in the Austin Chalk because of the deal pressure situation of the Eagle Ford as you get into Lavaca County. We also have to run a strength prop-in as I just said which adds to the gas but if you compare the economics with the Gonzales and Lavaca, the returns are about the same, the feet deep then is actually higher for Lavaca County but the returns are about the same because the reserves are higher in Lavaca County in spite of the higher drilling completion costs.
Just a few bullet points comparing these two areas, the depth in Eagle Ford and Gonzales is anywhere is from 8500 to 10500. Lavaca County is about 11,000 to 12,000 feet deep. The reservoir pressure becomes geo pressure as you go to the Eastern Lavaca County. This is reason why we have to set an intermediate string of pipe.
We can drill the top hole or an intermediate hole in Gonzales County with about 10 to 10.4 [pound] per gallon mud. Once we get into the Eagle Ford and Gonzales, we can maintain that mud rate once we get into the Eagle Ford and Lavaca County we actually have to wait up to 14 pound mud. So we have to get that top hole cased off from Lavaca County because of the mud weight, which as to the cost that’s a good thing of course because it does add to the reserves.
One thing we have seen initially, we expect the gas hole ratios to increase more appreciably as we got into Lavaca County, what we have seen so far we have about 500 cube of foot per barrel in Gonzales County to-date other than the last well we have drilled it’s been about the same 500 standing cube of foot per barrel then the quarry well which is the last well we drilled and completed in turned in line in Lavaca county is actually about a 1000 barrels or 1000 cubic foot per barrel. So it is not a lot difference but we have seen some increase.
And the graph that you are seeing up now we are a focused company, we sort of have become a one-trip pony in the Eagle Ford. It's a very high return kind of investment opportunity for us, considering our results to-date. We are focused on one area, which allows you to focus on cost that gets your people more focused on one area.
And we continue to transition from dry gas to oil and natural gas liquids. We do have a multi-year inventory of economic drilling locations in the Eagle Ford. We think that it is important for us to continue to add to that and diversify if we can with some of the new ventures ideas that we have drilled and will drill at the end of this year going into next year but not only increasing inventory, we are focused on our liquidity. We got more than sufficient liquidity through the end of the year but we feel like we’ve got an additional step yet to be determined exactly what we’re going to do in 2013 or in the beginning of 2013 to continue to improve it and get us over the hump.
So in any case, at this time we made a lot of changes in a short period of time for this company. Any of you who were familiar with Penn Virginia, a couple of years ago, we changed a lot. We were only natural gas and now, we’ve been able to increase our production to almost 50% oil in a fairly short period of time which I get my hand to our operational folks. Thank you very much and Jeff, I'll take any questions.
Thanks, Baird, we do have time for few questions.
Could you just clarify in your balance sheet any sort of principal payments that are due in the next one two years or three years as you’re alluding to and what your thoughts are in terms of being able to pay those off for refinance the debt?
Well, we sold Appalachia which rises almost a $100 million with that of course our borrowing base went from about $300 million and $230 million. We would expect which we are in the process of doing right now that are borrowing base is under review. We would expect it to increase because of our Eagle Ford program. I can’t tell you what it is at this time but we feel like we'll be in good shape going forward as far as borrowing base.
We do debt capacity as we continue to grow our EBTIDAX associated with Eagle Ford where we go out with bond debt, what we try to do JV in Eagle Ford where we saw additional assets to any and all of those or even a mix tag securities any in and all those options we made open to us, we have yet to determine what the plan is but we feel it, we get through 2013 as we continue to grow EBTIDAX that going in a 2014 and 2015 and we are being in a good shape, with any reasonable corporation with gas prices that being just taken today's strip.
So just specifically do you have any specific debt that is due in 2013 or ‘14?
No, we do not. First one, call on a bond side I think really it’s 2016.
So the liquidity challenges do you have a more regarding having sufficient working capital for your exploration efforts?
For drilling and exploration, yes.
Could you give us a sense for what you having any transportation challenge of getting either your crude or your natural gas out of the Eagle Ford?
We do not, we have a long-term contract with energy (inaudible), we got as of today we have got more than our capacity reserve through that plant more so than what we are actually producing and as far as the oil goes we are tracking all the oil rate now to multiple purchasers.
Ideally, we would like to get away from the [liaison] part of the tracking because just a sheer number of [run] ticks you got to handle is somewhat overwhelming. We really did tied to an old pipeline at some point in time and we are talking to a few of those folks right now, that we will commit to lay an oil pipeline to it. We would lay yet to be determined exactly how we would get to sign or may be lay toward our tank (inaudible) central location, we would lay to them whatever the case may be, but it’s something we probably need to do in a short period of time considering 6,000 to 7,000 to 8,000 barrels a day which continues to grow it becomes an (inaudible) number by the way. It gets somewhat overwhelming just to handle a stack full of [run] tick as that can be this higher every month.
Do you think increase GORs in the Eagle Ford overtime you mentioned that two counties that start but has pressured to complete as the GOR changing?
We have not, we have gone to in fact in most cases we have had to go to our official lift after some period of time depending on the well quality, the better wells of course you can delay that we typically go to gas lift that’s how we are officially lift our oil, in some cases we install pump jacks that we have seen we have not seen increase in GORs overtime have not.
What do you expect price realizations in Eagle Ford to be next year given infrastructure coming relative to LLS or TI?
I am sure I can't –
What do you expect price realizations in Eagle Ford to be in 2013 given infrastructure coming relative to TI or LLS?
Well, that is a magic question and unknown answer depending upon the flooding of the Gulf coast market by sweet oil. You know right now we are physically selling on a two to three-month time period and we continue to extend that by $7 to $8 premium, the WTI that is even net of transportation, so it is a nice premium.
What it is going to be this time next year, I have no idea. You really cannot put a hedge on a WTI to LLS basis. You can put physical locks in, but typically you can only sell them for short periods of time. There is no long-term liquidity in that basis. So we take what we can get with the premiums that we can get of course. But you know as you saw from the economic slide I showed. It is not to say we like to drilling the Eagle Ford well at $55 or $60 oil price which we probably would not that we can stand some downward pressure on net backs and continue to drill.
With your Eagle Ford well, just to kind of clarify, what sort of decline rates are you seeing in your one-year, two if you are starting let's say the 1000 barrels on the first day?
You'll typically see about a 65% decline in the first year. As far as exactly what it is in your two and three, I don’t have that off the top of my head, but of course that continues to decrease over time.
But first year is about 65% if memory serves me correct, these things act differently, not all of these are the same. As you get up in to the earlier part of the window what we have seen is lower IPs but the decline rate has not been significant.
You mentioned earlier that you will probably resume more activity in your gas assets if you saw poor oil pricing for natural gas, how would those returns compare in that pricing environment should the returns that you're seeing right now in the Eagle Ford?
I think they still would be less. I am not saying we would initiate drilling of gas prices to go to $4. In fact, the only thing we would even consider the $4 gas price would be Cotton Valley, the Haynesville and Mississippi Selma Chalk. $4 gas price would not be high enough to initiate any drilling.
So essentially those assets are just burning a hole in your pocket from a return perspective?
They are. It's something since its held primarily held by production and if those assets are not going any place, it is something that does have value, I guess, to the right party if you want to do something with somebody at some point in time. They are especially, the Chalk are probably very [MLT] friendly kind of assets because of the point in time and their decline in ample drilling opportunities under somebody who may drill for much lower returns but in any case, for right now, considering our liquidity issues, we're focused on oil and oil alone.
Anyway, we take a significant gas price increase for us to want to do anything. In fact, they may become trade [bake] if we wanted to pick up an oil asset and something else.
I would like to thank Baird for the presentation. Baird and Jim will both be available in the Riverside ballroom for the break up.
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