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Penn Virginia Corporation (NYSE:PVA)

Q2 2012 Results Earnings Call

August 2, 2012 10:00 AM ET

Executives

Baird Whitehead – President and CEO

Nancy Snyder – Chief Administrative Officer

Steve Hartman – Chief Financial Officer

John Brooks – Senior Vice President and Regional Manager, Gulf Coast Operations

Jim Dean – Vice President, Corporate Development

Analysts

JB Jouve – RBC Capital Markets

Jason Freuchtel – SunTrust

David Snow – Energy Equities Inc.

Adam Leight – RBC Capital Markets

Sean Sneeden – Oppenheimer

Ray Deacon – Brean Murray

Biju Perincheril – Jefferies

Eric Seeve – Golden Tree

Steven Karpel – Credit Suisse

Richard Tullis – Capital One Southcoast

Welles Fitzpatrick – Johnson Rice

Operator

Please standby. We are about to begin. Good day. And welcome to the Penn Virginia Corporation’s Second Quarter 2012 Earnings Conference Call. Today’s conference is being recorded.

At this time, I would like to turn the conference over to the President and CEO, Mr. Baird Whitehead. Please go ahead, sir.

Baird Whitehead

Thank you very much, Roxanne. Good morning. And welcome to Penn Virginia second quarter 2012 conference call. I’m joined today by various members of our team including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; John Brooks, our Senior Vice President and Regional Manager of our Gulf Coast Operations; and Jim Dean, our Vice President of Corporate Development.

Prior to getting started, we would like to remind you that the language in our forward-looking statement section of the press release as it was issued last night, as well as our Form 10-Q, which will be filed today, will apply to our comments this morning. We’d like to begin our discussion by expanding on the earnings and operational update press release that was issued after the close yesterday.

The second quarter continued a trend of solid financial results, with increasing cash flows from our growing oil and liquids production and decreasing operating expenses, helping offset declines in our gas production and natural gas prices.

Before we get into the details of the quarter, I wanted to touch on a number of recent developments which in addition to a strong first half of the year, are significant for Penn Virginia and consistent with our strategy and continuing to grow the oily part of our portfolio.

We did close on $100 million sale of our Appalachian assets. This was a very good price with a very attractive cash flow multiple. At the same time, we retained or will retain our Granite Wash assets, which still have a high component of liquids production and has -- also has an inventory of economic drilling locations that we will continue to exploit.

We have discontinued our dividend of approximately $10 million a year and both of these steps have helped improve our liquidity. And therefore, will help our capital expenditure program in the future.

We have had excellent early results from our Lavaca County Eagle Ford program, which has provided us an exciting addition to our oily drilling inventory and therefore, liquid reserve base.

We also have continued to experience solid reserve -- results from our initial acreage position in Gonzales County with our development drilling programs and in spite of selling our Appalachian assets, which were all dry gas, we do continue to retain our key gas reserves, which includes East Texas, Mississippi and the Granite Wash, which we consider will be essential modest recovery in natural gas prices.

For the second quarter we reported increases in product revenues, EBITDAX and cash flows relative to previous year’s quarter, primarily due to 161% increase in oil production, which is again attributable to the ongoing solid results of our Eagle Ford drilling program.

Product revenues of $76.2 million were up 4% over the second quarter of 2011, as our realizations increased 15% from $6.24 per Mcfe to $7.16 per Mcfe.

Oil and liquids revenues by itself were $65.9 million or 86% of our total product revenues this quarter, an increase of 90% over the second quarter 2011, due to the increase -- 161% increase in oil production and to a much lesser extent, a 4% increase in oil prices.

Adjusted EBITDAX of $60 million was up 20% over the second quarter of 2011. By the way, this is our fourth consecutive quarter of adjusted EBITDAX at or above $60 million. The improvement in EBITDAX was attributable not only to the 4% increase in product revenues, but also to a 17% decrease in direct operating expenses is a result of our continued focus on controlling costs.

These direct operating expenses decreased to $2.24 per Mcfe from $2.47 per Mcfe in the second quarter of last year, despite the 30% decrease in pro forma natural gas production.

With the sale of Appalachia, we will continue to make progress on bringing these operating expenses down, since Appalachian by itself, especially Horizontal CBM had a high operating cost component.

Our gross operating margin per Mcfe remained strong, increasing 30% from $3.78 per Mcfe to $4.92 per Mcfe in the second quarter of 2012, again due to our shift toward oil and natural gas -- or natural gas liquids, as well as lower operating costs.

Cash flow from operating activities increased 31% from $34.3 million in the second quarter of 2011 to $45 million in this year’s second quarter. During the first half of 2012, our cash flows from operating activities was -- almost $116 million, compared to only $64 million in the first half of 2011, an increase of 82%.

Adjusted loss was $10.8 million and adjusted earnings per share was negative $0.23, which includes the cash impact of derivatives and exclude charges for any impairments, restructuring costs and other non-recurring items. This is an improvement of $0.03 over the second quarter of 2011 and is due primarily to the increase on our gross operating margin.

Production of 10.7 Bcfe equivalent or 117 million a day was 4% below the production in the second quarter of 2011 taking into account the sale of our Arkoma assets. And primarily due toy 30% less natural gas production as we have purposefully elected to reduce natural gas drilling significantly over the last two years, in fact the last gas well we drilled was one of our Marcellus wells in the middle of last year.

That gas production decrease was partially offset by a 73% increase in pro forma oil and liquids production from approximately 460,000 barrels of oil in the second quarter of 2011 to about 800,000 barrels in the second quarter of 2012.

Oil and natural gas liquids production increased sequentially by 5% from 763,000 barrels in the first quarter of this year to again 800,000 barrels in the second quarter.

Second quarter production was 45% oil and natural gas liquids, as compared to 24% in the second quarter of 2011, and 43% in the first quarter of 2012. So we continue to rush that up. For all of 2012, we expect oil and natural gas liquid production to be about 47% of our total production.

Clearly, the Eagle Ford Shale was a primary driver of our growth, as we plan to spend almost 92% of our total CapEx in this play this year. Our results in the volatile oil window remain impressive and consistent and have on average very attractive economics.

Along with the premium oil pricing we have been getting since we sell into the LLS market, as well as continued emphasis on lowering our drilling completion costs, we believe we have a very strategic acreage position within this leading domestic oil shale play.

Our results to date, along with the location of our acreage in Gonzales and Lavaca county -- counties, puts us in a key position to demonstrate ongoing oil growth again with very attractive economics.

To date we have drilled 52 Eagle Ford wells, with 51 of those wells producing. The 51st well was just turned in line and we have yet to establish its initial potential.

First processing current gross Eagle Ford production is about 11,000 barrels a day equivalent, which is about 6,600 barrels a day net and has averaged 84% wellhead oil, 9% nitrous gas liquids and 7% residue/dry gas.

44 of the 50 applicable producing Eagle Ford wells have had an average peak rate at 1,000 barrels a day with a 30 day average rate of 657 barrels a day equivalent to the 43 applicable wells.

Six of the producing wells are not included in these statistics, primarily due to much shorter laterals and of course, much lesser frac stages. For the 43 full lateral length wells, we have averaged lateral lengths of approximately 3,900 feet and 16 frac stages.

In Lavaca County, our first four wells are producing and we just completed the fifth well, which is waiting on completion which we should start fracking here fairly soon.

We will spud soon the last of our earning wells on the farmout agreement. We’ve had better than expected results in Lavaca County and because of that, we plan on drilling four additional wells, excuse me, in addition to the original six, we had planned to drill, excuse me, for a total of 10 Lavaca County wells in 2012.

With this increased activity, we will earn all of the 13,500 gross acres under the original farmout or a minimum of 8,000 net acres in the AMI, assuming that that everybody participate for their working interest going forward.

In addition, the success of our Lavaca County exploratory wells along with nearby industry activity has given us further confidence that we now believe that a significant portion of this AMI acreage is perspective.

Originally, we had only valued the western half of the acreage because of an overall concern that as you go to the east the net pay decreases significantly. We still have this risk, but now we are more comfortable and more optimistic about the potential of the eastern half of this acreage block.

Also with the success in Lavaca County and steps taken to improve our financial liquidity, we’re going to bring back a third rig to this Eagle Ford drilling program late in the third quarter.

There will only be a slight benefit to 2012’s results by adding this rig late this year. We had already planned on bringing this rig back in the -- early in 2013. So this accelerates this plan by about three to four months. We now expect to drill 33 Eagle Ford wells, 26 net this year, which again will include 10 gross wells in Lavaca County.

As pointed out in the press release, with our current Gonzales County acreage and assuming we earn our minimum expected working interest in the acres in Lavaca County. Our acreage position in Eagle Ford in total is about 36,700 gross and 25,100 net acres. With down spacing and continued exploratory success, primarily in Lavaca County, we now believe that we have up to 250 total well locations.

If you remember it was not too long ago that we had represented that we had about 150 total locations. So I think we’ve added to that in a considerable period of time -- consider the number of wells that inventory in a fairly short period of time.

I also want to point out one other benefit we have seen so far on our acreage in Lavaca County. Originally, we thought as we go to the east our results would be gassier. In fact, it’s really not been the case. Our gas, oil ratios are about the same or just slightly higher than what we see in Gonzales County.

The other thing we have seen is our pour pressures/reservoir pressures are higher, something you would expect as you get structurally deeper. But typically you would expect it also had become gassier with the higher pour pressure. But what we are seeing is with the added benefit of the higher pressure and again an oily phase we think overall our reserves could be higher over time.

Lastly in the Mid-Continent, we continue to selectively participate on a non-operated basis in our Granite Wash wells. In addition, we are currently drilling our first high angle test well in the Viola Lime. It’s an oil prospect located in Jefferson County, Oklahoma.

We have about 9,600 net acres in that play right now, which we think some ability to expand that if successful, it’s a fracture carbonate allows about 7,000 feet vertical depth. I would expect we should have the results later this third quarter on that exploratory well.

To give you some more color on the financials. I’ll now turn it over to Steve Hartman, our CFO.

Steve Hartman

Thanks, Baird. Good morning, everyone. I’ll start with the review of our capital resources and liquidity. At quarter end, we had total debt of $785 million consisting of $600 million of high yield notes, $5 million of subordinated convertible notes and $180 million outstanding on a revolving credit facility.

Upon closing the Appalachian Basin sale on Tuesday, we received $93.2 million in cash proceeds and paid down $90 million on the revolver. Our revolver balance is currently $100 million, which is approximately where the revolver balance was when we started 2012.

We expect to receive another $4.5 million once certain [prep] rights and consents are satisfied. We have no debt maturities until 2016, other than the $5 million convertible notes that mature in November and our current availability is about $130 million.

As a result of the asset sale, the borrowing base on the credit facility was reduced $70 million to $230 million. Keep in mind this is an adjustment off our spring redetermination, which was determined as of March 31st. This is not indicative of what our borrowing base would be if they were to be redetermined today.

We expect we’ll earn back borrowing base value at the fall redetermination in September since we have added a significant number of Eagle Ford wells in production since March and we have significantly expanded our proved undeveloped locations in Lavaca County.

Besides availability under the credit facility, the other metric of liquidity I’d like to highlight today is our debt capacity. Our debt to adjusted EBITDAX ratio or leverage at quarter end was 3.1 times and adjusted for the asset sale which we sold at just over 6 times cash flow, our leverage ratio improved to 2.9 times.

The credit facility allows us to borrow up to 4.5 times our last 12 months adjusted EBITDAX, which adjusted for the recent sale is now $237.1 million. So under the debt covenant of the credit facility we could borrow up to an additional $360 million.

I’m not saying that we’d want to borrow that much money, but you can see that we have expanded our options going into 2013 with our current leverage under three times as a result of the asset sales.

Next a quick update on hedging. We have not added any new hedge positions since the last earnings call. But we had already aggressively hedged our oil production in the first quarter at very attractive levels.

We have approximately 67% of our oil hedge at the percentage of the mid-point of guidance, at a weighted average price of $101 per barrel. We have approximately 32% of our natural gas hedged, also as a percentage of mid-point of guidance at a weighted average price of $5.24 in Mcfe.

Our commodity hedges provided $5.6 million of cash proceeds this quarter and have provided $13.5 million year-to-date. Our current hedge portfolio is summarized for you on page 11 of the release.

Now on to guidance, our 2012 guidance is adjusted for the Appalachian Basin sale and guidance is summarized on page 10 of the release.

Total production guidance is being adjusted to $37.4 million to $39.7 Bcfe. The primary adjustment is natural gas production associated with the asset sale. We’re increasing the lower and upper ends of our oil production range to 2,160 to 2,290 MBO.

We are also raising the bottom end of our NGL guidance range to 775,000 barrels of oil equivalent and keeping the top end at 825,000 barrels of oil equivalent. We expect our percentage of oil and NGL production will be higher due to the asset sale now at 44% to 50% of total production for the full year.

For production revenue, we are now forecasting $284 million to $303 million. We lowered our expectations for oil revenue due to a change in our pricing assumption, down from 95% in the spring to our current level of $90. With the effect of the price decrease being partially offset by higher expected production volumes.

We’re also expecting lower NGL revenue due to low ethane pricing, especially at Conway. We continue to expect our oil NGL revenue to be between about 83% to 85% of total product revenues.

We’re raising the lower end of LOE guidance to allow for the higher LOE experienced in the second quarter, mostly from one-time events. But, overall, assume efficiencies will continue into the second half of the year.

We’re lowering our guidance for recurring G&A to reflect the sale of the assets, specifically due to closing of our Canonsburg office and we’re adding a restructuring guidance of $2 million to $3 million also related to closing that office.

We’re raising our guidance for adjusted EBITDAX by approximately $5 million to a range of $225 million to $245 million, even with the sale of the assets. We think the higher oil and NGL production, along with lower direct operating costs will more than offset the cash flow loss from the last five months of 2012 due to the sale.

To make it a little clearer, even though the asset was effective January 1st, we will still account for the assets as owned and operated through July 31st. So for accounting purposes, we only lose five months of production and cash flow.

We are reaffirming our capital expenditures guidance at $300 million to $325 million, even with adding back the third rig. We think savings in land and seismic expenditures along with lower well completion costs and the participation of our partner in the Lavaca County will largely offset the added cost of the third rig.

One final note, we did not give out spend guidance this quarter. Now that we have closed the asset sale, lowered our debt by almost $100 million and improved our leverage to below three times debt-to-EBITDAX, we feel we’ve addressed the out spend for 2012.

With that said, however, I wanted to remind you that in the previous guidance we had assumed a $30 million federal tax refund that we would be receiving in 2012. We still feel confident we will receive the refund and we’re hopeful we’re going to receive it in 2012, that’s the goal. But the IRS has been slow in giving out refunds lately. So it is possible that that refund maybe received in early 2013 rather than 2012.

And that concludes guidance review, Baird.

Baird Whitehead

Thank you, Steve. In conclusion I wanted to say that we remain committed to a strong and flexible balance sheet, with ample liquidity to position us to weather the challenges or to take advantage of any market opportunities that are out there.

Our decision to suspend natural gas drilling and any investments to natural gas, to sell assets in Appalachia which are really our legacy assets and to cut our common dividend were not easy ones to make.

However, these decisions will bolster our liquidity and reduce our indebtedness, which is very important to us right now and being able to continue to grow Penn Virginia and we think shareholder value.

I think you all agree that we’re making progress. We’ve got things to continue to do, but we have made a lot of progress here in the last six months or so. We have an exciting Eagle Ford play and with growth in oil production and reserves, along with any modest recovery in the price of natural gas which we are starting to see, we believe we will continue to reduce the GAAP to cash flows necessary to funds our CapEx programs internally. This is very important for us to ultimately accomplish.

With that, Roxanne, we’d like to go ahead and open up the lines for any questions, please.

Questions-and-Answer Session

Operator

Thank you. (Operator Instructions) We’ll go first to JB Jouve with RBC Capital Markets.

JB Jouve – RBC Capital Markets

Good morning.

Baird Whitehead

Good morning.

JB Jouve – RBC Capital Markets

My first question was about your Eagle Ford assets. With that third rig by the end of the third quarter, when you think you would be able to have all of your acreage held by production and also how much of that drilling activity is development acceleration versus acreage capture?

Baird Whitehead

Keeping -- starting our rig early this year in 2013, it does help earn acreage. I mean, we do have some lease expiration issues that we’ve recently placed little value on the farmout acreage.

So getting this rig early and allowing us to accelerate drilling in that farmout acreage does help us having to go back and having to renew acreage. I would estimate that by the end of next year we should -- with the use of three rigs we should have the bulk of our Eagle Ford acreage HBP.

JB Jouve – RBC Capital Markets

Okay. Okay. Thanks. And then maybe let me ask you another one about your Lavaca County acreage. So, even if we’re still at the early stage at this point and with those four wells, you do seem to have some good level of confidence about your expectations and it seems that, it compares pretty well with the Gonzales County acreage.

So you did mention that the gas to oil ratio, there’s no real increase as you go eastward. But I was wondering, if, probably you may encounter some higher pressure down there and as the formation gets a little bit deeper to the east. Does that have any effect on your well costs and therefore, on your returns as well?

Baird Whitehead

It does have an effect on the well costs. We have to set a string of -- we have to set an intermediate string to play in the Austin Chalk, which we do not have to do up in Gonzales County. So at the end of the day, setting out additional string costs as three quarters to $1 million incremental.

We also have to run or utilize the high strength prop-in because of the depth as compared to Gonzales County, which we now are pumping only white sand away because of the shallower depths. We think that Lavaca County wells will probably cost around $9 million to $9.5 million ultimately. We continue to make progress in bringing those costs down.

But because the reserves are higher. What we have seen so far in Lavaca County. We’re probably talking about 500,000 plus equivalent versus 400,000 plus equivalent in Gonzales County.

So even though there’s incremental costs, there’s incremental reserves and those incremental reserves are primarily oil at least based on what we have seen to date. So at the end of the day, our economics are still strong in Lavaca County even though the costs are higher.

JB Jouve – RBC Capital Markets

Okay. Okay. And then one last, one if I may. About the -- that Viola well, I was wondering if you could talk a little bit about the prospect, from a geology point of view, maybe at a high level and obviously, it’s early, but if you do give us any color behind your expectations for that first well.

Baird Whitehead

Well, the expectation, I think we modeled it at about 200,000 barrel unrisk per well. Drilling completion costs would probably be around $4.5 million to $5 million. It’s a very thick package of carbonate that’s fractured because of the geological complexity of it. We have 3-D over this prospect to help us figure out where to drill and what direction to drill.

It is a fractured carbonate. The merits of the prospect are because it’s fractured, horizontal well or high angle well in this case should help drain that reservoir faster. At the end of the day, can we find enough fractures with the well to make economical sense. So that’s what we’re trying to figure out.

But there’s running room, based on the position we have right now. I think we have 45 to 50 gross locations. If it does work, there’s probably some ability to expand it. There’s also a deeper prospect that we found after we shot the 3-D that I prefer not to talk about at this time that, at some point in time we may or may not drill. It’s not a given, we will drill it, but it’s a very pronounced structure that we saw in that 3-D.

So in any case, it was not -- the entry costs are fairly low. The acreage costs, I think our average acreage costs was about 250, 300 bucks an acre in this. So we don’t have a lot of money tied up in it, as far as I know, there’s nobody else making this play.

We tried to keep it as tight as long as we could, but I think somebody came out in one of their analyst reports and say, exactly where it was in Jefferson County. So the secret is out. So in any case, but that’s it.

JB Jouve – RBC Capital Markets

Okay. That’s a pretty thorough answer. Thank you.

Baird Whitehead

All right.

Operator

We’ll take our next question from Neal Dingmann with SunTrust.

Baird Whitehead

Hi, Neal.

Jason Freuchtel – SunTrust

Hey. Good morning. This is actually Jason Freuchtel stepping in for Neal.

Baird Whitehead

Great. Hi, Jason.

Jason Freuchtel – SunTrust

I appreciate all the commentary on the Lavaca County. Given the positive results in the Eagle Ford, going forward do you anticipate more Gonzales wells also?

Baird Whitehead

I would say, we’ll probably, this additional third rig, we’ll probably keep two rigs on and off in Lavaca County. I think that’s how we have to modeled. But sometimes we may have two rigs in Lavaca, sometimes we may have two rigs in Gonzales. So we’ll flip-flop back and forth.

Jason Freuchtel – SunTrust

Okay. Great. Thanks. And then the press release indicated you’re considering to look at acreage. In terms of M&A activity in the Eagle Ford, what have you seen recently?

Baird Whitehead

There’s still bolt-on acreage, where we’ve been successful in picking up bolt-on acreage. I don’t know if you paid attention to the details, but our acreage continues to increase, forget about the farmout. We continue to pick up nuts and bolts kind of acreage that’s adjacent to us at 500 to 600 or 1,000 acres a quarter.

We feel that we will take advantage of that going forward, we continue to do that. It’s pretty hard for us to rationalize getting into the M&A market for acreage in that area, because acreage costs tend to get so high and to the point that it makes no economical sense for us to pay some of the numbers that have been out there.

So we’ll continue to block and tackle, I guess, is the words typically used and continue to add on what we already have. And if there’s something out there that makes a lot of sense for us to do on an M&A standpoint or drill to earn, we would look at that very aggressively.

Jason Freuchtel – SunTrust

Okay. And then one last one for you. The Granite Wash activity has been scaled back a little bit, it looks like. Would you consider going non-consent in any of that activity?

Baird Whitehead

Well, in fact, we have gone non-consent. We are only sticking with the wells or staying in the wells that make perfect sense, as far as the economics go. Some wells as we have borderline economics and with that we have stayed out of those.

Jason Freuchtel – SunTrust

Okay. All right. Great. That’s all I had. Thanks.

Baird Whitehead

Thank you.

Operator

We’ll go next to David Snow with Energy Equities Inc.

David Snow – Energy Equities Inc.

Yeah. Hi. In the Lavaca…

Baird Whitehead

Hi, David.

David Snow – Energy Equities Inc.

… you are at 500,000, would that be an average for the whole earn-in block or just a portion of the acreage?

Baird Whitehead

Well, we don’t know, I mean, as we go to the east, there’s still some things we’re trying to get figure out. But basically we have seen so far, we feel pretty good about the 500,000. In fact, the initial well based on, I think we have about three months of production information. We think that’s about a 700,000-barrel equivalent well. So it’s a very good well.

David Snow – Energy Equities Inc.

How far east do you risk it as good, the whole thing now?

Baird Whitehead

Yeah. I mean, we still are pitting some geological risk of about 20% to 25% as you get real east, I don’t know, if I’m explaining that well. But we still have some risk as we go to the east because of the spending issue.

David Snow – Energy Equities Inc.

But overall, as an average you think 500,000 starting with the first well being as good as it is. The first one was more to the west, I guess?

Baird Whitehead

It was. I mean, we’ve only got four wells producing and out of those four wells, the most information we have is about three months. So we don’t have a lot of production information.

But there’s some offsetting information to the east that makes you feel good about our overall acreage position. But I’ll -- we’ll become gassier as we go to the east, first, we have seen so far. It could, but the 500,000 barrel number we feel pretty comfortable with right now.

David Snow – Energy Equities Inc.

Okay. And you mentioned you got a pretty good price per Mcf on the Appalachian. Can you give us some idea as to what you got on that?

Baird Whitehead

Steve, do you want to take that question?

Steve Hartman

Yeah. Sure. Well, we already mentioned that was trading at six times cash flow. It was $1.6 per Mcf based on our year end reserve report.

David Snow – Energy Equities Inc.

Okay. You decided not to do anything with the Granite Wash, but you were thinking about it. Why did you decide not to?

Baird Whitehead

Well, candidly we just didn’t get the offers that made us -- compelling enough to sell, because we think that not only oil prices but NGL prices, since they have got hammered so much in the Macon, made those bids come in lower.

So it made no sense for us to sell Granite Wash based on the numbers we had seen. It still generates $2 million to $2.5 million a month of operating cash flow. It still has drilling opportunities that are economic to us, so why sell. We got an offer for Appalachian that was very compelling. So we decided to go ahead and execute on that.

David Snow – Energy Equities Inc.

Yeah. What’s the well cost for your Gonzales Eagle Ford?

Baird Whitehead

Well, depends on well length, but probably at the end of the day about $7.5 million is good average for 3,900 to 4,000 foot lateral lane.

David Snow – Energy Equities Inc.

Okay. And what spacing do you envision out there?

Baird Whitehead

Well, initially we drill these thing is on 110, 120 acre spacing and ultimately we think and we already have in some areas, have brought that down to 60 acre spacing or about 450 foot between laterals. So, I think ultimately we will plan on down spacing to that lower acreage over a period of time.

David Snow – Energy Equities Inc.

That would be for Lavaca, too?

Baird Whitehead

Yeah.

David Snow – Energy Equities Inc.

Okay. Very good. You’ve really hit a nice one there. Congratulations.

Baird Whitehead

Thank you, David.

David Snow – Energy Equities Inc.

Okay.

Operator

We’ll take our next question from Adam Leight with RBC Capital Markets.

Baird Whitehead

Hi, Adam.

Adam Leight – RBC Capital Markets

Just go around way, I guess, Steve, the -- do you expect the borrowing base to increase to at least what it was or beyond in fall?

Steve Hartman

Yeah. I don’t know, if it will go to where it was before. In fact, we haven’t really got to the point where we’re willing to say a range. We’re so far out right now, that it’s hard to say. We have drilled -- we feel pretty confident that it’s going to go up because we have drilled 10 Eagle Ford wells all successful production is up.

We de-risked in Lavaca County somewhat, so there would be some spud value there. But as far as where we think the borrowing base is going to be, it’s too early for us to tell.

Adam Leight – RBC Capital Markets

Okay. And I guess, it sounds like you’re planning on running three rigs in the Eagle Ford for the 2013, is that correct from the current thinking?

Baird Whitehead

Yeah. That’s the preliminary plan.

Adam Leight – RBC Capital Markets

So, can I just get a sense if you’re going to be flipping back and forth in that well cost difference? What generally the impact -- we expect your CapEx might be looking like in?

Baird Whitehead

Well, we haven’t put any plans out for CapEx. I mean, considering I mean you can do the math. If you ran three rigs and your average well cost between Lavaca and Gonzales was 8 to 8.5 that would be a gross cost. You have to bring it down based on working interest, but that would give you some idea.

Steve Hartman

The big unknown, Adam, is the drilling schedule because the working interests in Lavaca County versus Gonzales County is so different that until we have a drilling plan in place, we really can’t dial in on an exact number. I think it’s safe to say that it wouldn’t be more than 2012.

Baird Whitehead

Yeah. That’s correct. And if we have success in the Viola or something, it might make sense for us to find a partner on something like that.

Adam Leight – RBC Capital Markets

And given what you have been -- you have running, what kind of number of completions do you expect, per rig, per month?

Baird Whitehead

John Brooks, you might want to take that question.

John Brooks

On Lavaca County, probably one rig will give us one completion per month. And in Gonzales County, it’s going to be one plus not real meaningful, I guess to say we’ll get one half wells completed per month, but that’s probably closer to what it would be.

Our best well that we got done in Lavaca County recently, we went from spud to sales in 29 days. And hopefully, we can repeat that going forward. There’s a lot of logistical things to overcome, but it’s quite a bit less in Gonzales County. Overall our spud to TD throughout the whole program is about 22 days and our spud to sales overall in the program is about 48 days.

Adam Leight – RBC Capital Markets

And is there sufficient infrastructure to go at the pace you want?

John Brooks

Yeah. Most of our wells are -- all of our wells so far are flowing to sales through our own pipelines within three to five days of flow back.

Adam Leight – RBC Capital Markets

Okay. That’s great. And then…

Baird Whitehead

We have sufficient capacity on the processing facility to take care of our gas lines.

Adam Leight – RBC Capital Markets

Okay. And I know its early days, but higher you are, higher pressure. Would you expect your decline curve to look similar or somewhat different?

John Brooks

I think it would look similar. It may be a little bit better, because of the higher pressure and because of the back pressure we’re holding on these wells. We’re holding more back pressure on these wells in the Lavaca country because the pressure overall is higher.

Adam Leight – RBC Capital Markets

Okay. And then given your lack of gas drilling, can we get a sense now after the sale of what you think the underlying decline rate is on the gas production?

Baird Whitehead

If you take into consideration everything absent Appalachia, probably 20% or so, 20% to 25%.

Adam Leight – RBC Capital Markets

That’s hopeful. And then would you be thinking about putting the Granite Wash back on the market, if the marketplace improves or is that just…

Baird Whitehead

Well, it’s always an option. I mean, we’re not going to do it immediately.

Adam Leight – RBC Capital Markets

Right.

Baird Whitehead

But it’s always an asset that we would consider. We have other assets we may consider, also.

Adam Leight – RBC Capital Markets

Okay. That’s great. Thanks.

Baird Whitehead

You’re welcome. Thank you very much.

Operator

We’ll take our next question from Sean Sneeden with Oppenheimer.

Sean Sneeden – Oppenheimer

Hi. Thank you for taking the questions.

Baird Whitehead

No problem.

Sean Sneeden – Oppenheimer

On the Appalachian sale, I think one of the previous callers asking you about it, but can you sort of walk us through how that deal transpired? I know the Granite Wash deal, the economics didn’t make sense, based on where the NGLs were. But did EnterVest approach you guys or how did that deal really take place? And perhaps as a follow-up to that, can you talk about why they didn’t want to purchase the Marcellus assets?

Baird Whitehead

Well, we knew that the Granite Wash was not going to meet our expectations. And we were not going to sell it at the kind of price levels that we had been hearing. So we decided to actually put our royalty stream. We refer to it as mango royalty on the market.

It’s a royalty stream of about $6 million, $6.5 million a day and EnterVest decided to make an offer on everything we had in Appalachia. We thought it was a compelling offer, so we decided to go with it.

As far as the Marcellus goes, we decided to exclude Marcellus, even though we have not done any recent drilling. We feel, considering where our acreage position, we’re not going to get a lot of value for it in today’s market. It made no sense for us to sell it. So we decided to hold onto it.

We’ve got remaining term on the leases that we can manage. So, we will just continue to sit back and watch what’s going on. And if it made sense for us to do something with the Marcellus at some other point in time, we would reconsider at that time.

Sean Sneeden – Oppenheimer

And that’s helpful. And then maybe thinking about some -- I have some questions on CapEx a little bit differently. Basically I think what I’m hearing is that you guys are planning to spend cash flow next year, is that a fair assumption?

Baird Whitehead

It’d be hard to do that, no. I mean ultimately, that’s our goal. But I don’t think we’ll get to it next year.

Sean Sneeden – Oppenheimer

Okay. And then Steve, could you perhaps tell me, I think I missed this, what the pro forma revolver balance was?

Steve Hartman

As of the -- as of right now, it’s a $100 million.

Sean Sneeden – Oppenheimer

Okay. Great. Thank you very much.

Steve Hartman

You’re welcome.

Operator

(Operator Instructions). We’ll go next to Ray Deacon with Brean Murray.

Ray Deacon – Brean Murray

Hi. How you doing?

Baird Whitehead

It’s great.

Ray Deacon – Brean Murray

I was wondering, if the deeper target in the Viola line area is that something that’s worked elsewhere, I guess are there any analogs to that, or is that kind of a wildcat?

Baird Whitehead

No. There is analogs in, Ray.

Ray Deacon – Brean Murray

Okay. Got it. And I guess have you seen any improvement in NGL prices, since the second quarter and what do you expect for the second half?

Baird Whitehead

Well, there’s been some recent improvement in NGL prices. We decided to -- I think Steve mentioned, when he was speaking. We are rejecting ethane right now in the Mid-Con because high ethane prices got down to $0.03 to $0.04 a gallon, so it made more sense for us to go ahead and keep it in the gas stream.

It’s improved recently up there. We will probably go back to recovering it next month, just keeping an eye on it. Mont Belvieu prices are still strong enough, we -- it clearly makes sense for us to continue to remove ethane down in our Eagle Ford production. But Mid-Con has been where the problem is.

Ray Deacon – Brean Murray

Got it.

John Brooks

We know it s -- this is mostly an essay and maybe a little bit of a propane problem. The heavies haven’t really on impacted that much.

Ray Deacon – Brean Murray

Got it. Got it. Okay. Great. I guess it just in terms of your assumptions about the Eagle Ford acreage, are you certain that your partner is going to elect to participate going forward? And if the three rig program continues to see the kind of results you have seen so far could that 200 on drill number of locations increase between now and year end?

Baird Whitehead

Well, I don’t know exactly what our partner is going to do. I mean they have consented on the most recent wells. There’s no reason for us to expect, at least based on -- I think they view us as a very confident operator. And based on that and based on the results. I would see no reason why they would not continue to participate.

To answer your second part of that question, as we continue to drill wells to the east in our Lavaca County acreage, it would add locations. We’ve not put any locations into the eastern part of that acreage at this point in time until we get it completely derisked. So it would add some additional locations once we do get it derisked.

Ray Deacon – Brean Murray

Okay. Got it. Thanks.

Baird Whitehead

Thank you.

Operator

We’ll go next to Biju Perincheril with Jefferies.

Baird Whitehead

Hi, Biju.

Biju Perincheril – Jefferies

I think – hi, good morning. A couple of questions. What’s your plans to test the eastern portion of the Lavaca County acreage, now that you’re drilling additional wells this year?

Baird Whitehead

Well, probably try to step out and get one drilled later this year. It will be riskier and challenges because where it is, but we need get over there and drill a well and see what we have, to answer the ultimate question of course. But I would say late this year, we will.

Biju Perincheril – Jefferies

Okay. Just one test this year. And then it looks like the 250 well locations, probably you’re not using the down spaced, you’re not assuming down spacing across your acreage. Can you remind us how many wells do you have that are sort of 400, 500 foot apart and what the history has been?

Baird Whitehead

John, do you know the answer to how many wells we drilled with the -- that are down spaced that close together?

John Brooks

Yeah. There were three wells that were drilled at the closer spacing. And I think they’ve all averaged pretty much right around the mean, as a whole. So, the rest of the acreage is mostly drilled on 1,000 to 1,200 foot spacing between well bores.

Biju Perincheril – Jefferies

Okay. And those three wells, which acreage block were they located on?

John Brooks

The main part of our Cortez acreage.

Biju Perincheril – Jefferies

Okay. And what’s your plan for testing that on some of the other blocks you have?

John Brooks

Well, I think our primary plan is to HBP, our acreage throughout our Eagle Ford holdings and test the eastern side of the Lavaca County before we devote a lot of resources to the infill.

Biju Perincheril – Jefferies

Okay. If I look at you well counts even in Cortez, it looks you’re assuming somewhere close to 100 acres per location, is that correct? And as you gain more confidence in that infill program that number is likely headed higher, is that a fair statement?

Baird Whitehead

It is. As John said, we will try to get the bulk of our acreage HBP with a larger spacing and come back selectively and down space.

Biju Perincheril – Jefferies

Okay. That’s all I had. Thanks.

Baird Whitehead

Thank you, Biju.

Operator

We’ll go next to Eric Seeve with Golden Tree.

Eric Seeve – Golden Tree

Hi. A few questions. One with respect to cash flow in 2013, who knows exactly where commodity prices will be, but as you mentioned looks like you will meaningfully out spend your cash flow.

And who knows where your volume base windup, but it looks like things are potentially going to get pretty tight. Are there other options that you’re thinking about to help alleviate potential liquidity issues?

Steve Hartman

Okay. Well, Eric], as we mentioned earlier, we’re not really getting into 2013 yet. But your point being that it’s getting tighter and what are our options? We have already said that we are planning on out spending cash flow in ‘13. It will be meaningfully less than what we’re out spending in ‘12, we think because we don’t think our program is going to be any more expensive than ‘12. And our cash flow has been getting higher.

So we think that it’s not going to be as much of a cash out spend. We don’t know what our borrowing base is going to be yet either in this fall or next spring, as we continue to drill Eagle Ford wells. And as far as what our options are for financing 2013, we kind of look at it very similar to how we approach 2012.

We’re at 2.9 leverage right now. So we have all the options available to us. We have availability to term out debt. We could look at additional assets sales. We have some non-core assets that are very gassy, as Baird mentioned that have value, especially in a little bit higher market.

We have that $30 million tax refund that’s coming, either in late 2012 or early 2013. So basically what I’m saying is, we don’t really know right now, but we have all the options available to us. And as we get closer to ‘13, we’re going to analyze each one of those.

Eric Seeve – Golden Tree

Okay. Thank you. Second question on Lavaca, did I hear you -- did you just say to a previous caller that the plan is to drill one well next year in the eastern part of the play where you have a little bit less geological certainty? Did I hear that correctly?

Baird Whitehead

We’ll probably try to get it drilled by the end of this year in the eastern part of the acreage, right, at the very end of this year, beginning in next year, it may slop over to next year. But we are working our way to the east as part of our development program anyway.

But we probably need to go ahead and just step out and drill one to the eastern part of our acreage to get the ultimate question answered. And we will do that, again, either late this year, beginning next year.

Eric Seeve – Golden Tree

Okay. Thank you.

Baird Whitehead

You’re welcome.

Eric Seeve – Golden Tree

And with respect to the rest of the drilling, is it just stay kind of as far west as general, where you have better conviction in the geology until lack of locations there pushes you further east, other than the one step out?

Baird Whitehead

Well, no. I mean we’ll continue to drill wells in the western part of our acreage and try to pick up some additional acreage in and around what we already have to add to our inventory. But as we continue to derisk the acreage as we go to the east, then we will go ahead and drill that layer of wells, if you understand what I’m saying. So it is sort of a simultaneous kind of process.

Eric Seeve – Golden Tree

Okay. Thank you. And just lastly, I guess a philosophical question on the Appalachian sale. And I certainly appreciate why you -- the rationale and needing to sell the asset. But it seems like in terms of the value, six times cash flow for what -- who knows where gas will be, but it is certainly feels like we could be looking back and looking at the LTM period as sort of the trough of gas pricing.

Six times cash flow for a long lived assets with very high proved developed proportion of its reserves. It sounds like you guys thought that was relatively attractive and just trying to get a sense of that. It didn’t -- it doesn’t scream out as being attractive. And just wondering is that based on a negative view on gas pricing or a commentary really on what the M&A market would bear for other assets today?

Baird Whitehead

Well, it -- we thought it was attractive because -- yeah, I mean, considering the type of asset we typically have back east. There’s very little wells for us to drill. We would probably need a $6 plus gas price environment to even resurrect drilling back there because the bulk of the drilling remaining was horizontal CBM kind of wells.

Acreage was falling apart. We’re losing spuds. There was no sign in the near-term that we can make any sense out of drilling wells. The operating costs in the horizontal CBM stuff is high. So we felt it was the right thing to do to go ahead and take it off the table, let somebody else have it. It helps our operating costs.

We -- it’s not right, crazy about shutting down offices, but it also resulted in us being able to close our Canonsburg office. It takes some more overhead out of the overall organization over a period of time. So, again to focus on fewer plays versus more plays.

Steve Hartman

It also helped us to delever, Eric]. We sold it at almost six and a half times cash flow and our covenant in the credit facility is four and a half times cash flow. So it actually helped us on the leverage standpoint, too. Not just bring cash in the door, but actually helped the overall situation. It increased our options.

Eric Seeve – Golden Tree

Great. Thank you. And just lastly with respect to the borrowing base, it seems like the real constraint there is the determination of the borrowing base as opposed to the leverage covenant. Am I thinking about that the right way or am I missing anything?

Steve Hartman

I’m not sure I understood your question.

Eric Seeve – Golden Tree

It seams like the limitation on how much bank debt you can draw under the facility is going to be what the bank sets the borrowing base at, as opposed to brushing up against the leverage test. Am I thinking about that the right way?

Steve Hartman

You’re correct. As far as what we can access in immediate liquidity from the banks on the credit facility, it’s the borrowing base that is our limiting factor, not the leverage.

Eric Seeve – Golden Tree

And the leverage test, is it 4.5?

Steve Hartman

4.5. Right.

Eric Seeve – Golden Tree

Thanks, guys.

Steve Hartman

You’re welcome. Thank you.

Operator

Okay. We’ll go next to Steven Karpel with Credit Suisse.

Steven Karpel – Credit Suisse

Hi, gentlemen. I guess there is a follow-up to Eric’s question there. You went through and listed off some of the options for potential liquidity enhancements in 2013. Would you guys consider doing equity at all to help fund that gap?

Baird Whitehead

It’s always -- it’s a basket of options we have. I mean, that’s the way to phrase it. I mean the overall security market, in general, is always an option. I’m not going to say we will never do it but we have a basket of options to solve this problem. We have yet to figure out the best way to do it and we’re going to move ahead.

Steven Karpel – Credit Suisse

Okay. All right. I appreciate it. Thank you very much.

Baird Whitehead

You’re welcome.

Operator

We’ll go next to Richard Tullis with Capital One Southcoast.

Baird Whitehead

Good morning.

Richard Tullis – Capital One Southcoast

Okay. Thank you. Good morning.

Baird Whitehead

Hello, Richard.

Richard Tullis – Capital One Southcoast

Hi. Congratulations on a good quarter. I think most of my questions have been touched on already. But I wanted to ask about the latest batch of Eagle Ford wells in Rock Creek, the ones with the shorter laterals. How do you attribute the difference in the early production rates versus the group of shorter laterals in that same area that were presented in the 1Q update? Looks like it took a step back there.

Baird Whitehead

John, do you have -- do you have an answer for that question?

John Brooks

Yeah. There are some shorter laterals there and the production reflects that, but the well cost also is proportionately reduced with those. We’ve now HBP’d all of the Rock Creek acreage. We’ve got some other opportunities to go back there with a -- what we hope is another partner in the early part of next year. But the shorter laterals do yield the lower IPs, but on a per stage basis. And the overall capital, it’s in line with everything else.

Baird Whitehead

I don’t think there’s -- we don’t think there’s a geological issue, Richard.

Richard Tullis – Capital One Southcoast

Okay.

Baird Whitehead

….that caused that. It was -- these wells are fairly close to some very, very good wells we have drilled in Rock Creek. In fact, Rock Creek in general has probably been our best area, as far as results go.

Richard Tullis – Capital One Southcoast

Okay. What do you see as the average lateral for Rock Creek the second half of the year?

Baird Whitehead

John, do you have an answer for that?

John Brooks

We’re done drilling in Rock Creek for this year.

Richard Tullis – Capital One Southcoast

Okay. I got you. I think that’s all I had. Thanks a bunch.

John Brooks

Thank you.

Operator

We’ll take our next question from Welles Fitzpatrick with Johnson Rice.

Baird Whitehead

Hey Welles.

Welles Fitzpatrick – Johnson Rice

Morning. This is kind of building a little bit on Biju’s question. But in regards to Eagle Ford spacing, it seams like southwest Gonzalez, Cannonade and Shiner are spaced a little bit broader than the rest. Is that a function of having less wells in southwest Gonzalez, Cannonade and I guess, south Shiner or are you actually seeing something geologically that’s different or is it just being conservative?

Baird Whitehead

Well, Cannonade was somewhat a different animal because it is shallower structurally within the overall Eagle Ford. We went in there and drilled a few wells. Those wells were somewhat below the mean. We certainly had not written off the area. We think we have kind of figured out what we would do better.

We’d probably drill longer laterals on the Cannonade to improve the economics. But it’s a lesser animal, I guess, what I’m trying to say, in Cannonade or at least part of Cannonade, because of where it is structurally. But we will -- we have wells planned to drill in Cannonade. I think -- correct me if I’m wrong, John, it would just tend to be longer laterals to be more efficient with the economics.

John Brooks

Yeah. That’s correct. The acreage at Cannonade has not been as driven by the HBP need elsewhere and there were some geologic issues like the Baird alluded to over there. And we think we’ve got a planned development going forward to develop that acreage. And we will be revisiting it here very soon. And hopefully before the end of the year, have at least one more well drilled in that vicinity.

Welles Fitzpatrick – Johnson Rice

Okay. And then on Shiner and Gonzales, is it a lack of well control or are you also seeing something different there?

Baird Whitehead

It’s just a lack of well control. We’re just taking it -- we’re just being very precautionary as far as how we test Shiner. Sitting back, drilling, analyzing the results of those wells, getting them online and just be more regimented, I guess what I’m trying to say, on how we develop it.

And then we will come back in, after we get come production information across our entire acreage position and start selectively exploiting it with downspacing. If there are some poor geological areas that we do have a geological issue, of course we would probably not come back and drill another well, unless we could drill a longer lateral. But in general, we will come back in and exploit our better areas with downspacing over time.

Welles Fitzpatrick – Johnson Rice

Okay. And one last one, and at the risk of being overly optimistic, some folks now have a Utica map hooking east into northern PA. Most of them cut off before it to all’s Marcellus acreage. But do you have any data through the Utica there? Is it present? Presumably it would be dry. But have you seen anything that would be something else in that?

Baird Whitehead

No. There’s one -- I think there’s one well that’s not too far away. The interval is there. We do think it would be dry gas, which really tweaked our interest here. As you may or may not know, National Fuel I think has a well and it drilled to Utica and Elk County, which is not that far from our acreage in southwest part of Canada. It would be a good data point to have.

I don’t think they have completed that well yet. I think they -- I think they will soon. So that would help us evaluate our acreage once they get that well completed. But we do think that, -- we do think at least based on analysis that we have done, the Utica gets very thick up in that area, also.

And that’s really another reason that we decided not to sell our Marcellus at this time, because there may be the chance that Utica does come into the limelight at some point in time, even up there, where this really is no data point.

Welles Fitzpatrick – Johnson Rice

Perfect. That’s all I have. Congrats on the quarter.

Baird Whitehead

Thank you.

Operator

We’ll take our last follow-up question from David Snow with Energy Equities, Inc.

David Snow – Energy Equities Inc.

Yeah. Hi. What is the -- you said 45 to 50 gross locations possibly for Viola. What’s the net of that?

Baird Whitehead

Probably from a well, kind of, standpoint, probably 25 to 30. That would give you a good net to gross.

David Snow – Energy Equities Inc.

And if you are successful in your first one, does that sort of derisk a good part of the rest or are they all going to be individually kind of a wildcat?

Baird Whitehead

Well, I think the results of this first well are key. Would we walk away from it based on results that did not meet our expectations? Probably not. We would probably drill a second well, David. A fractured play, by definition, you’re going to have sort of results all over the place, both very good and not as good.

So that would be an -- in fact that was an expectation going into it. But we think this first well will be a good data point.

David Snow – Energy Equities Inc.

Statistical play, basically?

Baird Whitehead

Yeah.

David Snow – Energy Equities Inc.

And then you mentioned, you might have another partner on the part of the Eagle Ford -- the one you just talked about, Rock Creek. Are you trying to take on that as a way of funding or why would you take a partner when you’re doing so well?

Baird Whitehead

Well, what John Brooks was talking about, there’s some acreage down there that it makes sense to unitize with somebody else. That helps squares off the acreage, that actually adds gross locations to us that we have not considered right now. So it’s actually a benefit to us. It’s just unitization of acreage. No money would change hands. It just adds -- it’s a JV kind of arrangement that helps add gross locations.

David Snow – Energy Equities Inc.

Okay. Fine. Thank you very much.

Baird Whitehead

All right. David.

Operator

That was our last question. Mr. Whitehead, I will turn the conference back to you for any additional or closing remarks.

Baird Whitehead

Well thank you very much for listening in. We got a lot of interest this phone call, probably more so than I have seen in recent history, anyway. So in any case, again we’re making progress and we look forward to giving the results to you in the third quarter.

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