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EV Energy Partners, L.P (NASDAQ:EVEP)

Q2 2012 Earnings Results Conference

August 10 2012 10:00 AM ET

Executives

John B. Walker - Executive Chairman

Mark A. Houser - CEO, President and Director

Michael E. Mercer - CFO and SVP

Ronald J. Gajdica - SVP, Acquisitions

Analysts

John Ragozzino – RBC Capital Markets

Kevin Smith - Raymond James & Associates, Inc., Research Division

Praneeth Satish - Wells Fargo Securities, LLC

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Brett Reilly - Credit Suisse Securities (NYSE:USA) LLC

Adam Lake – RBC Capital Markets

Brian Kuzma - Weiss Multi-Strategy Advisors

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the EV Energy Partners Second Quarter Earnings Conference Call. During today’s presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions)

I’d now like to turn the conference over to Mr. John Walker, Executive Chairman. Please go ahead, sir.

John B. Walker

Thank you, and good morning. Welcome to EV Energy Partners second quarter earnings call. I’m in El Paso, while Mark Houser, who is having his birthday today. Mike Mercer and Ron Gajdica are in our Houston office.

This has been a very good quarter for EVEP. We exceeded the midpoint of guidance on production, LOE and distributable cash flow. G&A expenses were slightly above the expectations because of acquisition transition cost, which we do not include as part of our G&A guidance.

Obviously, natural gas and NGL prices hurt revenues for everyone this quarter. Our extensive hedge position however, particularly for natural gas and natural gas liquids provided the cash flow support we expected and needed this quarter and for the remainder of 2012. I’m particularly pleased with the $0.695 per gallon ethane swaps and the $1.028 per gallon propane swaps that we’ve put in place last December. And Mike Mercer will provide more financial information in a while.

You will see in the 10-Q that EVEP, in August entered into an agreement to purchase about $83 million of assets. For competitive and strategic reasons we cannot disclose location of these assets yet, but we will inform you later in the year.

As a point of clarification, Chesapeake announced this week that affiliates of EnerVest are buying its Midland basin position. This is a purchase by EnerVest’s institutional fund and EVEP is not a party to that transaction. Our Utica sales process own operated acreage is underway and we’re encouraged by the level of interest. We’ve had meetings on both the operated and non-operated packages. We plan to keep the shallow Clinton production, the deep Knox production, our recorded overrides and EVEP’s investment in the Midstream. Therefore we’re only marketing the Utica formation rights and delivering approximately an 80% net lease.

EVEP’s perspective Utica acreage in some non-core Ohio Counties and a few Northwestern Pennsylvania Counties will not be marketed this year. But it’s our intention to test this acreage and sell it in the future. I’m spinning most of my time on this landmark Utica effort. However, I’ve met with many CEOs of oil companies and spend quite a bit of time in meetings in Japan, Korea, and China. As I’ve said publicly before the wet-gas window is significantly derisked. The cost of Utica well to drill and complete is now a little above $6 million, one half the average cost from last year.

Chesapeake is drilled at least two wells on several multi well pads this year and in fact they plan on drilling six wells on one pad this year. The results from offset wells to some of our early Carroll County wells are two to three times better than those from the year-ago.

In the early stages of drilling results in the oil window, we and other Utica companies have proven that we’re able to produce oil plus gas in the NGLs and expect these results to continue to improve. Specifically we need to improve upon completion techniques and appropriate dissipation periods for the oil windows. And that’s just a very natural process and looking at the Eagle Ford, we believe that the results from oil wells in the Utica oil window right now are in excess of those from the early wells in the Eagle Ford.

Mark will address the encouraging results from EVEP operated wells in Stark and Guernsey Counties, the Chesapeake operated [Granby] wells performance from a six stage frac in Tuscarora County and the Anadarko and Antero wells in Guernsey and Noble Counties. Our Cairns well in western Carroll County and Habrun well in Southern Stark County, further supports the attractiveness of this window is we test them over the next month.

Now I’d like to turn the call over to Mike Mercer.

Michael E. Mercer

Thank you, John. For the second quarter of 2012 our adjusted EBITDA actually $66.1 million, which is a 20% increase over last year’s second quarter and it is primarily due to acquisitions we completed during 2011. And it’s a 3% sequential increase over the first quarter of 2012. Distributable cash flow for the second quarter was $34.5 million, a 4% increase over the second quarter of 2011 and basically flat versus the first quarter, even with the decline in commodity prices.

Distributions for the first quarter which are payable on August 14th, to the holders of record as of August 7, will be approximately $33 million. For the second quarter, production was 10.7 Bcf of natural gas, 282,000 barrels of crude oil and 403,000 barrels of natural gas liquids or 14.8 Bcfe. This is a 47% increase over the second quarter of last year, which is primarily due to the acquisitions that I had mentioned completed during the fourth quarter of 2011 and a 2% sequential increase over the first quarter production of this year of 14.5 Bcfe.

Second quarter net income was $15 million or $0.35 and $0.34 per basic and diluted weighted average LP unit outstanding respectively. I would like to note several items that were included in net income for the quarter. We have $15.5 million of unrealized gains on commodity and interest rate derivatives. And these unrealized gains were due as you know to a decrease oil and NGL prices that occurred from March 31st to June 30th, partially offset by an increase in future of natural gas prices and the effect of such price changes on the mark-to-market valuation of our outstanding commodity derivatives.

We had $0.7 million of non-cash realized losses on derivatives acquired in 2010 acquisition that settled during the quarter. We had a $0.5 million or $0.04 per Mcf of production non-cash charge to LOE related to oil and tanks purchased in connection with our 2011 acquisitions, excluding this amount, LOE for the quarter would have been $1.64 per Mcf of production.

Other items to note are we had $1.7 million of dry hole and exploration costs. This was almost exclusively seismic related costs for the quarter. $16.3 million impairment charge, this was primarily related to our write-down of certain of oil and natural gas properties to their fair value due to the effects of declining commodity prices on expected future cash flows from these properties. $0.4 million of non-cash deferred income taxes, $3.8 million of non-cash compensation-related costs contained in G&A and in addition contained G&A were about $0.6 million of property acquisition due diligence transaction and transition related costs related to the acquisitions we made in the fourth quarter that we are still carrying over to this year.

Those are the key highlights on our financial performance. What I would like to do now is turn it over to Mark Houser for review of our operations. Thank you.

Mark A. Houser

Thanks, Mike, and good morning, everybody. First, I will start out with our base business, which performed very well last quarter and continues during this half summer to do well. It’s interesting I was in both New York and Ohio this summer, and it was harder there than it was in Houston. We’ve been really feeling the heat across the country that our operating guys have really done well. It’s evidenced by both our production and our cost performance.

As Mike and John had mentioned, we’ve managed to stay towards the good end of both production and costs. Net equivalent production grew inline with our projections at little over 2% versus the previous quarter. We realized this production growth while once again standing under our capital guidance. We’ve guided around $40 million to $50 upstream spending for the quarter, while we actually spend about $33 million. Most of this reduction was result of slower growing activity in the Mid-Continent and Appalachia conventional areas.

The last quarter we mentioned we’re reliving the full-year capital forecast intact. For guidance purposes of this fall, we’re still staying at projected full-year forecast, but I’d expect this to end up the year’s spending below are currently estimated $160 million for upstream activity.

Lease operating expenses actually declined slightly on both an absolute and per unit basis due to a combination of good well surveillance, lower fuel prices and enhanced product marketing arrangement. Actually per unit production costs were down over 13% for the quarter.

In the Barnett Shale, which accounts for over 40% of EVEP’s production, we started to feel benefits of the scale of assets we’ve put together in the area. Production has grown from 68 million equivalent per day in February to over 71 million a day in August. This represents a 5% increase in six months. This production growth would likely have been even higher, but we’ve had issues with some of our gatherers, primarily Crosstex as they’ve had some mechanical challenges. We will continue working to minimize the line restrictions. We’ve several other looping and compression projects in the plan and we will continuing to work with our Midstream people to help bring these projects in over time and give us more capacity.

During the quarter we brought on 17 wells including our first wells from our Encana acquisition. We’ve increased our emphasis in the northern areas, as they’re typically more liquids rich. The first few wells we’ve bought online this quarter looked strong. We now have planned about 78 gross wells for the year. And we’ve drilled 36 through the first half of the year. This will be about a three rig program for the rest of the year. And the wells are little more expensive about $3 million per well versus $2.2 million in the southern areas, at better targeted rates about over 2 million equivalent a day around 2.3 versus our original targets of about 1.2 and are oilier, so provide a better return.

We’re seeing reductions in pumping costs and are getting continually more efficient in drilling and completing Barnett wells as we move along. One area that’s been a strong performer over the last several months is been our Appalachia conventional production, which represents about 20% of overall production. Thanks to good production surveillance, some good Knox wells late last year and a warmer winter, which reduced our house gas obligations, production has stayed above our budgeted levels. This is despite limited drilling activity and some significant pipeline restrictions, namely the Hastings plant.

Now let’s turn to the Utica. EVEP’s Utica acreage position at Ohio is about a 150,000 net working interest acres. We also have the equivalent of the 2% override on approximately 880,000 gross acres. Many of you’re aware of the recent series of production announcements that have come out over the past few days as activity in the Utica continues to increase. Considering our acreage spread, we’re encouraged by it all.

The news on the Gulfport Wagner well, which is over 4,000 BOEs per-day and Harrison County is encouraging. Chesapeake’s disclosure on the Brown, Bailey, Snoddy each over 1,400 BOEs per day in the wet-gas window and the [Granby] wells are all encouraging. It should be pointed out that the [Granby] well which has a disclosed rate of about 560 BOEs per day in the liquid window is only completed with six stages across 2,200 feet of Point Pleasant. There are plans to complete the additional 3,700 feet of unfracked lateral. If you adjusted that well for full fracked length the normalized rate would be over 1,500 BOEs per-day.

Our joint venture with Chesapeake and Total is moving forward in the wet-gas window. Chesapeake is currently operating 11 rigs in the Utica, and plans to operate 15 rigs by the end of the year. Drilling wells for the JV in the liquids rich area of the play. Total is paying a 60% carry on its 25% interest in these JV wells. The plan is for over 500 wells to be drilled by the end of 2014. This JV is very busy. EnerVest’s participation in the JV includes five wells currently producing, 12 wells that are either flow testing or shut in, 15 wells dissipating, 17 wells completing or waiting for cement, three wells drilling and one – and 11 additional wells recently AFEed for our approval including one I just got on email couple of minutes ago.

Drilling continues to be active, but it’s still mostly focused in the liquids window. Drilling times are improving as the industry gains more experience in drilling in the area. Utica horizontal wells are now routinely being drilled in 15 days from spud to total depth, which is significant improvement even from last quarter. Many of our AFEs are now coming in below 7 million. We generally agree with Chesapeake’s assessment that they will eventually approach 6 million.

Now moving to the Utica oil window, first production from three wells in Noble and Guernsey Counties was announced by Anadarko. Also CONSOL has stated publicly that they’re all window well in Tuscarawas County, is producing in commercial quantities. Also there has been mentioned just recently I believe down in Noble County of a well of Antero that looks – it sounds like its in the liquids window, but its got a pretty high room of rate as well. So, again activity is moving south as well.

EnerVest itself has now completed four operated Utica wells. The RHDK #8H located in the oil window in Guernsey, the Frank #2H well and the oil window in Stark. The Cairns well and the wet-gas window kind of on the edge of the oil window in Carroll and the Habrun well in the oil window in Stark County. The Cairns and Habrun wells are currently in the dissipation period. The Frank #2H well in Stark County was drilled and completed with over 6,600 feet of horizontal section, 24 frac stages and over 170,000 barrels of frac water injected.

Normally oil wells are brought online using artificial lift, such as gas lift or rod pumps - especially to help lift up some of the frac water. After a 60 day dissipation period, the Frank well was brought online without any artificial lift assistance and flowed 515 barrels of oil equivalent per-day while unloading some of the frac water. So far we’ve unloaded about 6% of the frac water, so not much of it yet.

80% of the equivalent production of the 515 BOEs per-day is liquids and 40% of the total stream, so that have of that 80% is like 47 degree API oil. While the dissipation period appears to have been somewhat effective, we’ve shut the well in to complete target in the sales and to install standard gas lift equipment, which will help to unload the well and improve the rate.

For those of you that are familiar, as familiar with producing oil operations its very standard for some sort of artificial lift to be installed to assist lifting the oil and water, compared to the Barnett Combo oil even the Bakken, the Eagle Ford oil, the Wolfcamp, all these areas oil wells are typically pumps are put on almost immediately all the time. So again, we’re very pleased with the unassisted rate and look forward to getting more information once we get it on gas lift, which we anticipate over the next couple of months.

Now moving to the RHDK in Guernsey. This is a very short 3,400 foot lateral with 13 stages and a 1,000 barrels of frac fluid that were injected. Please note this is an EnerVest operated well, EVEP does not own, have an interest in the well, but nonetheless EnerVest is operator. This well was originally drilled by Chesapeake and was taken over by EnerVest when Devon acquired Chesapeake’s position in this County. The short length of this lateral is primarily due to lease configuration. We’ve now completed the dissipation period and we’re currently placing the well on being pumped to help lift the oil and get through the completion fluid recovery stage. And we will have production information later on that well.

I will note that we had gotten some samples on that and it looks like its about – again 47 degree API crude with a pretty large content of liquids – oil and liquids and not a very high content of gas for what we can tell. So, again we’re starting to see the evidence of real oil wells.

So, overall we’re cautiously very encouraged by the initial rates from the oil window. We still believe there is lots to learn about completion techniques, including lateral landing, frac stages, effective proppants, flow back, dissipation etcetera. But the reservoir is flowing oil in commercial quantities. Our early economic assessments of this play looked very encouraging. We’ve also, as John mentioned, taken a look back at the initial horizontal oil wells in the Eagle Ford. If you normalize the Frank well, actually it looks better – normalized for time that is taken back to day one, the Frank well actually looks better than the very early Eagle Ford wells.

Changing gears a bit, Midstream infrastructure in the Utica play continues to be developed. EVEP is participating in two Utica midstream companies. We have a 9% interest in Cardinal Gas Services, a company that provides low pressure gathering in the Chesapeake, EnerVest, and Total JV area. EVEP also has an 8% interest in the Utica East Ohio Midstream, a company that was formed with momentum that will provide gas processing, NGL fractionation and the pipeline connects for the JV production, as well as other production in the area.

The first wet-gas to be processed from the Utica will occur this December when the first train of the Dominion plant, located in Natrium, West Virginia, becomes operational. This will be followed in 2013 with the commissioning of several other Ohio gas plants, including those operated by Momentum and MarkWest.

As we’ve discussed, EnerVest including EVEP is working to monetize all or portion of its acreage position this year. We continue to work with Jefferies, our investment banking advisor in this process. Phil DeLozier, our Head of Business Development for EnerVest and Ron Gajdica, are playing big roles in coordinating the process.

The data room is open and active. We’re encouraged by the interest we’ve been receiving from several potential buyers. We will consider joint venture swaps and/or outright cash sales and we’re getting interest on all of those. We hope to close the deals later this year. So far 2012 is continuing as expected and will be a real intriguing year for EVEP. We’re going to keep trying to modestly grow production in our areas where we’re making a return. We are staying disciplined and if natural gas prices stay low they’re brought up a little bit lately, but we’re still very focused on later return on our capital drilling. And we’re looking forward to the next several months as we should see a lot of additional Utica shale production and information from well results from a number of companies that are active in the play. And while we focus on all this we’ll continue to look for good acquisitions particularly small PDP oriented deals.

So with that, John, I’ll turn it back to you.

John B. Walker

Okay. Thanks Mark. I think that we’re ready for questions.

Question-and-Answer Session

Operator

Thank you, sir. Ladies and gentlemen, we’ll now begin the question-and-answer session. (Operator Instructions) Our first question is from the line of John Ragozzino with RBC Capital Markets. Please go ahead.

John Ragozzino – RBC Capital Markets

Good morning, gentlemen and happy birthday Mark.

Mark A. Houser

Thank you.

John Ragozzino – RBC Capital Markets

Can you just confirm the rate on the Frank well was a 24 hours IP rate?

Mark A. Houser

Yes.

John Ragozzino – RBC Capital Markets

Okay, fair enough. Do you have any expectation for further expansion of the liquids cut as you push further out west and there’s a not a lot of activity that’s been done on them, but I know you’ve got some data from existing cores and such?

Mark A. Houser

The liquids window does seem to be moving a little bit West. I think we’ll see a lot more on that over the next little while but these recent announcements are certainly encouraging with that.

John Ragozzino – RBC Capital Markets

Okay. And then Mike, just moving to kind of a hypothetical situation; can you walk me through any potential payments to the GP that might be triggered by such a significant liquidity events such as the monetization?

Mark A. Houser

Well, our expectation would be that we would either do an asset swap or redeploy the proceeds into acquisitions of high PDP content, long-wide oil and gas properties, so the expectation would be that, that we would use that cash to reinvest, grow the business, increase our EBITDA which would therefore increase distributable cash flows, so the GP would benefit through as well as the – of course all the common unit holders would benefit to increases in distributions.

John B. Walker

Yeah, John the GP probably has 2% interest, so that would be its benefit.

John Ragozzino – RBC Capital Markets

Okay, that’s what I meant. So just the IDR split you did raised the distribution significantly would eventually step up, but I was just wondering if there is any one off item that I hadn’t been aware of?

John B. Walker

No.

Mark A. Houser

No, as we as we raised the distribution, it moved into the IDR splits clearly the GP would benefit from that.

John Ragozzino – RBC Capital Markets

Okay, great, and just a couple of quick, two more. Is there any material difference that you’re seeing in terms of specific completion techniques across different peers of yours that you’re aware of?

Mark A. Houser

You’re talking about in the Utica in particular?

John Ragozzino – RBC Capital Markets

Yeah.

Mark A. Houser

No, nothing. It’s interesting because I think Chesapeake’s philosophy has been that they try several different things until they have enough data across a random sampling that they can kind of see some trends. Now again, I am not going to debate too much. Those guys are good and they’ve done it in many areas. We’re being a little bit more deliberate and trying to move one or two things at a time.

But so far, we’re not seeing – we’re not doing things a whole lot different from others, except I would say we tend to be focused a little bit on shorter frac stages than Chesapeake has. I think they have been more towards 400 feet and we tend to be smaller than that so far, but we’ve only really got a couple of wells that completed in there and they’re in the oil window not the wet-gas. So, I think that remains to be seen. There’s will be a lot of evolution here just like there is in every shale play as to what really works.

And within the Utica there will be, whether its oil window, gas et cetera there’ll be a lot of different, I would formulas put together on completion. I'll say we’re talking to partners. We’re talking to Anadarko who now is dissipating their wells, we’re talking to them and we’re talking to Chesapeake. We actually, through our data process have some data sharing we’re doing with some of the other operators in the Utica, so we’re talking to all of them and trying to learn as much as we can from them.

John B. Walker

Yeah, I think we have mentioned 11 data sharing swaps.

John Ragozzino – RBC Capital Markets

Okay. That’s very helpful and just one last one, kind of expand on that. You guys have clearly done your homework on the progression of similar plays I mean such as like the Eagle Ford that you referenced before. Can you comment on maybe the most impactful developments made across the learning curve process that you’ve seen?

Mark A. Houser

Well, one of the things we’re having to factor in on that is these early Eagle Ford wells in the oil column were drilled several years ago and completion techniques have changed a whole lot. So, as much as I say that, hey these early Eagle Ford wells that were better than the early Eagle Ford oil wells. We don’t have enough data yet to really normalize what was done frac wise on those wells.

So, we still have some to learn on that, but again we’re talking to several many other operators about their experiences, and that’s really a good thing for us from Chesapeake being a partner with Chesapeake in some of this because again they have done it in other areas as well. Another thing to say is, we do have experience frac and wells in several areas including up in the Cleveland Sand, the Austin Chalk, the Barnett and our technical teams are meeting all the time both internally and externally to just try to learn more.

But, I would say probably the main thing compared to the early Eagle Ford wells is going to be the number of stages, and the volume of profit pumped and I don’t have enough data to really give you specifics, but those are the kind of things we’re looking at.

John Ragozzino – RBC Capital Markets

Very helpful. Thanks very much gentlemen, and great quarter.

John B. Walker

Thank you.

Operator

The next question is from the line of Kevin Smith with Raymond James. Please go ahead.

Kevin Smith - Raymond James & Associates, Inc., Research Division

Hi, good morning gentlemen.

John B. Walker

Good morning, Kevin.

Kevin Smith - Raymond James & Associates, Inc., Research Division

And happy birthday Mark.

Kevin Smith - Raymond James & Associates, Inc., Research Division

The Frank well only completed with six stages, can you kind of expand on some of that?

John B. Walker

Yeah, this is a [Granby] well that was completed …

Kevin Smith - Raymond James & Associates, Inc., Research Division

Or is that the [Granby] well that only completed with six stages? What was the process or thought on that?

Mark A. Houser

Well again, Chesapeake is the operator of that well, but I believe initially the plan was they were going to frack part of the well, I guess that would be the toe of the well a certain way and then come back and they’re really considering I believe a propane frack or some sort of a gas frac on the heel and they just haven’t done that yet. They have been monitoring this well and drilling and completing other wells. So, that was the thought process on it at the time, Kevin.

Kevin Smith - Raymond James & Associates, Inc., Research Division

Got you. And how many frac stages was the Frank well done with?

Mark A. Houser

24.

Kevin Smith - Raymond James & Associates, Inc., Research Division

Okay, got you. And then how long was the Frank well shut in for?

Mark A. Houser

60 days.

Kevin Smith - Raymond James & Associates, Inc., Research Division

60, okay. And then lastly when do you expect to bring the next two wells online?

Mark A. Houser

Probably -- we’re still debating in dissipation. I know as an example, Gulfport has focused on the 60 days in the liquid window as we have. As we move into the oil window we’re still trying to figure out given the more dissipation or less and so we’re debating even internally right now. Is it going to be 60 days, 75 days, 90 days somewhere in that range; so we’re working on that. And see, what the answer to that is, if you’re talking about sometime in September to October we should be bringing the well on.

Kevin Smith - Raymond James & Associates, Inc., Research Division

Got you. Is there any way, I mean, are you just basically judging it by production rates to figure out the dissipation, there’s no way of testing that is it?

Mark A. Houser

A couple of things you look at, and again this is a new area for a lot of folks, but a couple of things you look at is, obviously its production rate of your liquids and gas but it is also the production rate of your water. How much water is in fact dissipated? Again I mentioned I think on the Frank well, we pumped in about 170,000 barrels of frac water in the process. We’re not going to dissipate every barrel of that, some of its going to come back. And part of what you look at and I know they have done that in the Eagle Ford as you look at initial water rates in addition to initial oil or gas rates coming back to help you determine how your dissipations work and so those will be the things we’re paying attention to.

Kevin Smith - Raymond James & Associates, Inc., Research Division

Got you, very helpful. Nice quarter. Thanks.

Mark A. Houser

Thank you.

Operator

The next question is from the line of Praneeth Satish with Wells Fargo. Please go ahead.

Praneeth Satish - Wells Fargo Securities, LLC

Hi, good morning. Just couple of quick questions on the Frank well, could you maybe provide the composition of the NGL stream in terms of present ethane, propane versus the heavier components?

John B. Walker

It’s approximately 45% ethane and 55% C3 plus.

Praneeth Satish - Wells Fargo Securities, LLC

Okay. And could you comment on EnerVest long-term goal for the Permian properties being acquired from Chesapeake, could those end up in the MLP at some point?

John B. Walker

Well as I said the Middle Basin assets are during 2012, and I have no idea at this point in time. We haven’t closed the transaction yet and that’s pretty far down the road but it would probably be an appropriate asset EVEP at some point in time but that’s -- but we probably have somewhere between $1 billion and $2 billion in EnerVest institutional assets that are appropriate for EVEP right now.

Praneeth Satish - Wells Fargo Securities, LLC

Okay. And one last question just on the overwriting royalty interest, just wondering if you’re receiving any of that cash flow right now and maybe if you could provide just a preliminary outlook on how big of a driver that could be in 2013?

Mark A. Houser

I think that we’re starting to get some information on that. Again, in terms of just getting frankly royalties paid and typically it takes a little while. We’re starting to get data, but we probably ought to wait to report later on that. We don’t have enough information on that in a consolidated basis yet to provide that, but we will when we get a little bit more data in.

Praneeth Satish - Wells Fargo Securities, LLC

Okay. Thank you.

Operator

The next question is from the line of Ethan Bellamy with Robert W. Baird. Please go ahead.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Hi, guys. Lots of questions for you. John, just to start off with, you had, you talked about your Asian road-show there has been some political pushback on the Nexen Buyout, how big of a factor do all you think are political factors in getting a deal done with certain buyers?

John B. Walker

Well, I think that when you’re talking about CNOOC in $15 billion transaction versus I was here primarily showing the Non-Op package because that would be more appropriate and I can say that we had some excellent meeting with companies that are interested in the Non-Op package but they have a gigantic amount of camp closure where some of the governments are providing backstops in terms of their investments in oil and gas molecules all around the world which is completely contrary to our government. So, we’re extremely encouraged about the interest that we’re getting from U.S. international companies on the operated package and then from financial firms and foreign players in the Non-Op package.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay. And I was kind of surprised to see the acquisition, it seems like that – you guys have said earlier that acquisitions were somewhat on hold until the Utica disposition.

John B. Walker

And they are. But, like I say, we’re using that. We have a large credit facility. We’re buying that with debt and it’s something that -- I think my early statement is appropriate. We just can't talk about it right now for competitive reasons. But, given a little bit of time when we’re not in a competitive situation we’ll disclose it and you’ll like it.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay, good. Now, with respect to and just on that same one with making with respect to potential drops from EnerVest that’s more of a 2013 and beyond that as well?

John B. Walker

I am not sure about that. One of the things that has provided some constraints is price of natural gas and so, yeah we’re not prepared to do it right now, but we – I do think that there is potentially a large amount of assets that we could drop into EVEP and that of course has to, we use GP or not ultimately making that decision. The independent Directors of the EVEP have to approve the offer and the individual institutional funds advisory group, have to approve dropping the asset down. So it’s not necessarily a simple process because we want to make sure that we’re fair to both parties.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay.

Mark A. Houser

And Ethan, just to comment to that, as an example suppose we're able to secure a cash deal for EVEP’s acreage this year as we’re expecting and hoping and planning to do. If indeed a swap with one of the parties is not there, you have a certain amount of time to do the like-kind exchange, but doing a dropdown could conceivably serve as that like-kind exchange and so we’re gearing up to valuate assets within EnerVest, Ron is actually involved in that. So, if that opportunity presents itself we’ll be prepared to make that offer to EnerVest even this year. If -- again if that makes sense and if of course as John said EnerVest private equity will have to agree to that as well, but those wheels are in motion although actually those wheels are in motion all the time around here, that’s just how we think about things.

John B. Walker

Yeah, Ethan on the 1031 exchange you have to identify the asset within 45 days and complete it within six months.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

That’s an interesting option, I hadn’t considered. With respect to the production from the silver of interest in the Chesapeake JV, what type of impact do you expect to have from that in terms of ballpark in maybe ’13?

Mark A. Houser

Ethan, we’re actually about to head into our budget process and we’ll probably start looking more towards 2013 guidance. With the dissipation process, you’re starting to see more and more wells now amounts from Chesapeake and I think they even mentioned in their call about the number of wells that are coming online. I mentioned it as well. We’re starting to get a sense of when things will come on and we can start doing the math, the excel spreadsheet type of math you do to bring these wells on at the appropriate time. So, I would like to kind of differ on that answer until we have little bit more data here and can provide guidance that makes sense in that regard.

John B. Walker

Yeah, and let me add just a little added perspective to, is with the Hasting plant being up and down and up and down and the Natrium plant for Dominion not on yet, but we expect it to come on in December. The wet gas line has been impacting Hasting being down, and so some of the wells that have been in dissipation period would already be producing if there was a wet gas line to put the product into. So we’re still being impacted by a lack of processing and of course there’s a lot of processing coming on in the first half of next year, with Momentum we’re bringing on quite a bit of the capacity.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay. What is the accumulative investment in the midstream businesses so far and how much CapEx would you expect to be dedicated to that by year-end and next year?

Mark A. Houser

It’s around $20 million to $25 million in that ballpark, our total number for the year.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

For this year?

Mark A. Houser

Yes.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay. And anything for next year?

Mark A. Houser

Yes, there will be. And Ron do you have – do you happen to have those numbers for next year nearby? Ethan, let’s keep going with the questions, Ron will fill that number in for you in a minute.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

All right. What do you think the LOE is going to be on a Utica well particularly the one you just brought on?

Mark A. Houser

Well on per – let me see if I have that in our assumptions. I have an assumption on some of the tight curve stuff and I don’t have that with me, but I am looking – it’s probably going to be similar to a lot of our Chalk wells in terms of operations.

John B. Walker

With the – listen Mark, since this is such a dry formation, we’re not going to be dealing with very much water in the Utica.

Mark A. Houser

Yeah.

John B. Walker

Yeah, I’ll remind you that its 1% to 5% water saturation and so once you have gotten rid of the load water you’re not going to have any formation water that you’re producing, that always helps particular in wet gas and NGL window where we have over 95% of our wells.

Mark A. Houser

Looking at some of the numbers we have Ethan, it will somewhere between kind of $0.50 and $0.75 [per M] on op costs is what we’re looking at right now, but that’s pretty early in terms of trying to.

John B. Walker

In terms of 2013 capital for Utica Midstream, it’s expected to be in the $50 million to $75 million range.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

Okay, that’s helpful. And then a last one, I’ll let somebody else jump in here. What kind of proppants are you using on those wells and is there any constraint there?

John B. Walker

We’re using – Ron, do you want to comment on that?

Ronald J. Gajdica

Yeah, different proppants are being used for different wells. And some wells have cross-linked gel, some wells are just thick water and some wells are a combination. A lot of different completion techniques are being tried and as we get more production results and we see what's working best not just in terms of IP but in terms of maybe six months worth of production. We’ll begin to get some feedback as to what's best, but we’re still in the lining and optimization mode. So there is no standard yet.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

But, some are lower pressure, so you don’t need high-end ceramics right?

John B. Walker

We are not – we have used some ceramic chasers on the very end of some of the jobs that certainly Chesapeake has done and we have done, but it’s not a high volume and so far as a matter of fact we’re getting lots of interest from service companies who just want market share in the Utica. So, in terms of access to anything that’s not an issue at this point at all.

Ethan Bellamy - Robert W. Baird & Co. Incorporated, Research Division

All right. Thanks for the detailed answers guys, I appreciate it. Good luck.

Operator

The next question is from the line of Brett Reilly with Credit Suisse. Please go ahead.

Brett Reilly - Credit Suisse Securities (USA) LLC

Good morning, guys.

John B. Walker

Good morning.

Brett Reilly - Credit Suisse Securities (USA) LLC

I just had a quick question. I know John, you had mentioned, you guys have excluded some acreage from the package being marketed today. Can you provide any further color around how many net acres are in the operator package that’s being marketed right now?

Mark A. Houser

We’re not providing information on that right now.

Brett Reilly - Credit Suisse Securities (USA) LLC

Okay. And then, I guess maybe moving back to the Frank well for a bit. Any cost estimate there for, how much capital did you guys put into that one?

Mark A. Houser

Into the Franks, in particular?

Brett Reilly - Credit Suisse Securities (USA) LLC

Yeah.

Mark A. Houser

I don’t have that in front of me, but it was around $8 million or a little bit higher than that.

Brett Reilly - Credit Suisse Securities (USA) LLC

Okay.

John B. Walker

Yeah, let me remind everybody that the first well drilled is about a five acre pad. And I think the Frank well ultimately will have about a 14 mile pipeline to it, and so if you isolate just on the drilling completion it’s one thing, but if you assign the pad that’s probably going to have six to nine more wells drilled off of it. Those probably equally should have to pay for the pipeline as well as the pad and some of our pads are costing $700,000 to $1 million to build.

Brett Reilly - Credit Suisse Securities (USA) LLC

Got it. And I know you had kind of provided, you said you had kind of some tight curves estimates in front of you, at least initial ones any thoughts there in terms of and willing to share kind of the EUR, as you guys are looking for on the oil wells?

Mark A. Houser

No, we’re so early we’re not looking at that. I would say for our marketing purposes we have looked at, we have gone anywhere from the downside of 200 barrels a day IP on oil to things that are way up above that. I’ll just say that generally the return’s looks really good even on a 200 barrel a day well because again costs are coming down, we’re expecting most of these wells to be kind of in the say six to seven, but towards the low end of that. As we get into the manufacturing process, we’re already seeing many AFEs below $7 million coming in now. So, generally the returns look good, but again it’s just too early for obviously for in technical reviews with folks in a data room environment we’re are providing some of that data, but we’re just not providing it on a broader basis right now.

Brett Reilly - Credit Suisse Securities (USA) LLC

Okay.

John B. Walker

Yeah, the AFEs from Chesapeake on pad well drilling are now just slightly above $6 million.

Brett Reilly - Credit Suisse Securities (USA) LLC

Got it. All right, that’s all from me. Thank you guys.

Mark A. Houser

Thank you.

Operator

The next question is from the line of Adam Lake with RBC Capital Markets. Please go ahead.

Adam Lake – RBC Capital Markets

Hey, good morning.

John B. Walker

Good morning.

Adam Lake – RBC Capital Markets

Just a couple of quick ones. Mark, I don’t know if you can answer this, but do you have a sense on order of magnitude how much production increase you might get from putting it on pump?

Mark A. Houser

The key to that Adam is inflow performance ratio, IPR it’s called, it has to do with reservoir performance which Dr. Gajdica here can explain a lot more than I can, but I remember some of it. Basically it’s the pressure loss you have across your reservoir. And we still don’t really understand the permeability and the flow characteristics of Utica oil. So, it’s – we just don’t know.

On the other hand, as we flow back, as an example the Frank well, after we fracked it we were getting very large volumes back of -- as we first brought it back on its mostly just frac water. And that well was flowing in excess of 1000 barrels a day of frac water back. Now some of that is due to the fact that it’s, you put pressure on it. The other part it is due to the fact that the well seems to be willing to give up something. When we put the pump on it, it should be able to give up a lot of fluid. As John, mentioned the water saturation of this reservoir is very low. So, once we get either pull dissipation of some of the frac water and the other frac water to flow back. If the reservoir allows that it should give up fluids and the pump will give it the ability to do that. So, generally we’re hopeful it will come back at a really strong rate, but we’ll wait and see. Did that make sense Adam?

Adam Lake – RBC Capital Markets

It does and you answered my second question too.

Mark A. Houser

Okay.

Adam Lake – RBC Capital Markets

Then finally just, upcoming borrowing base, any sense of with the acquisition and what you’ve done otherwise, what direction that might go?

Mark A. Houser

Yeah our borrowing base redetermination is in October, Adam. Clearly from what we’ve seen we would expect there to be some decline in prices that banks are using on their price stats, which would hit everybody a little bit. We don’t see any significant effect on that right now though on borrowing base.

John B. Walker

Yeah, you have to remember how well hedged we are and they do take that into consideration. They discounted some but …

Mark A. Houser

Yeah, we run some scenarios with potential price stats that banks might be using in the fall, which are lower than where they were back in April, primarily on gas, but which I think it’s a little too early but we wouldn’t expect any significant change.

Adam Lake – RBC Capital Markets

Okay, that’s great. Thanks.

Operator

The next question is from the line of Brian Kuzma with Weiss Multi-Strategy Advisors. Please go ahead.

Brian Kuzma - Weiss Multi-Strategy Advisors

Hey, good morning guys.

Mark A. Houser

Good morning.

John B. Walker

Good morning.

Brian Kuzma - Weiss Multi-Strategy Advisors

I did want to understand a little bit more on the dissipation technique and …

John B. Walker

I am not sure it’s a technique it’s – we're just shutting at the end and there’s more models yet, and so we are clearly in the dry gas window you don’t need to shut it in as much as you do in the oil window and it -- so we like in the Eagle Ford we learned about it by accident and so I think that it’s just a learning curve issue.

Mark A. Houser

Brian, what is your specific question?

Brian Kuzma - Weiss Multi-Strategy Advisors

My question I guess is, like was there any anticipation that when you guys are doing the shake & bake that you won't need to put it on artificial lift or why wasn’t the first well put on artificial lift?

Mark A. Houser

Well, we actually we anticipated putting it -- we planned it all along for this well to be on artificial lift. I mean, we already have the gas lift line kind of running – again there is not a lot of gas or anything in this part of Stark County that we could use for gas lift. But, we had set the wheels in motion to put this on artificial lift. What we wanted to do was to, because I want to step back.

The reason is again this is an oil well and oil wells typically because of the weight of the column of oil in a tubing string typically performed a lot better if there is a gas lift or a jet-pump or something that’s helping pump this fluid up the tubing and keeping the weight of the reservoir so to speak.

So, we planned on a long to do that, but because we’re in a brand new play, we wanted to see what the reservoir itself would do without any help. That’s why we brought this Frank well on for, kind of a few days and not many but a few to see how it’s going to do on its own, because in with guys like Ron can go through a better job of modeling inflow performance, the IPR thing I mentioned to really determine what the reservoir is capable of. If we start lifting it from absolute day one, we won't have the ability to do that, it will be mass by that lifting technique.

John B. Walker

If you have a 6000 foot deep well, and its filled with oil when it has a density of 0.4 PSI per foot, that’s 2400 PSI of back pressure on the well and if you can release that back pressure to something closer to zero it’s should make a significant difference on the productivity of t he well.

Mark A. Houser

What the dissipation process does is again when you frac this well with all this frac water, is if it’s working right, the clays which are under saturated as John mentioned absorbs some of the water. So I use it as an example, we injected a 170,000 barrels of frac water into the Frank well. So in theory you should get back 170,000 barrels, it will flow back. But through dissipation instead of maybe getting 170,000 barrels back you might get 30,000, 40,000, 50,000 barrels the rest of it will have basically stuck the reservoir. And if you do that, if you get less water back that’s going to help to get more oil back sooner and lift better, but you still want artificial lift.

Brian Kuzma - Weiss Multi-Strategy Advisors

I got you. And in this first well, the Frank well, is it flowing up casing or tubing and what is the pressures look like, the flowing pressures?

Mark A. Houser

Can you repeat that, I’m sorry.

Brian Kuzma - Weiss Multi-Strategy Advisors

I was just curious if the well is flowing up casing or tubing, right now?

Mark A. Houser

Well, the well is shut in right now, but the well was flowing up tubing.

Brian Kuzma - Weiss Multi-Strategy Advisors

Okay.

Mark A. Houser

Yeah. We in for safety reasons, we had a packer set below the tubing and so basically what we did we floated up the tubing and (indiscernible) creates tubing. And then once we had gone a little bit of production off of it, we shut it in, we pull the tubing, we ran the gas-lift mandrels and installed the gas lifts valves, but we’re in the process of getting all that put together and getting this well ready to put to sales.

Ronald J. Gajdica

Yeah, and in terms of flowing tubing pressures, it can be anywhere to zero to several 100 pounds, depending on what you’re doing to the well, whether you’re swabbing it, what kind of choke you have on it, how it slugs in early time. There are number of variables that are going to affect the pressure and we really just need to get it all on a stable artificial lift, on any well either a pump or a gas lift mechanism to get stable flow, get the slugs out and then we will see what we’ve got. It certainly ought to be better than what we currently have.

Mark A. Houser

Yeah, that’s right. And as an example this is different again, there is so much more on these oil wells that are oil and liquids and so much less is gas compared to these – to the liquid window wells that – they’re not going to require as much lift. In fact, a lot of those may flow for a while or a good while even on their own, whereas the oil wells consistent with the Bakken and with the Wolfcamp and others that will be pumped.

Brian Kuzma - Weiss Multi-Strategy Advisors

Okay. And then another question was just looking at these well costs, when you talk about Chesapeake AFEs coming in a little over $6 million, is that just D&C or does that include all the pad work and the hook ups in the batteries and everything?

Mark A. Houser

The pad work is typically built into the first few wells, okay. And so – yeah, and so these coming in now as John has referred already on pads and so there is not a lot of incremental costs to drill these. And so really if you amortize, that’s actually where we come up with about maybe 6.2 to 6.4, that’s kind of taking the overall pad costs and amortizing them over six wells. So, the answer is when you getting the $6 million or $6.1 million AFEs that is with less pad cost because you’ve already – you have upfront paid for it.

Brian Kuzma - Weiss Multi-Strategy Advisors

Okay. All right. Thank you, guys.

Operator

There are no further questions at this time. I would now like to turn the call back over to management for closing remarks.

John B. Walker

Well, we appreciate it. We’re – we do feel extremely good about what’s happening both in the wet-gas window and the oil window. And I can tell you that we have some entities, they’re looking at the operating package, that are only interested in the oil window, which is the most valuable part of it, just as – the same is true about the Eagle Ford. So, we’re encouraged that we and others are flowing well and so that we’re now in the process of trying to improve upon our techniques here. Thank you for taking the time to listen in on our call.

Operator

Ladies and gentlemen, this concludes the EV Energy Partners Second Quarter Earnings Conference Call. You may now disconnect. Thank you for using ACT conferencing.

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