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Executives

John B. Walker – Chairman & Chief Executive Officer

Michael E. Mercer – Chief Financial Officer

Mark A. Houser – President & Chief Operating Officer

Ronald J. Gajdica – Head of Engineering and Acquisition

Analysts

Kevin Smith – Raymond James

Adam – RBC Capital Markets

Ethan Bellamy – Robert W. Baird

Unidentified Analyst

Yves Siegel – Credit Suisse

Michael Blum – Wells Fargo

Steward Starling – Private Investor

EV Energy Partners, Ltd. (EVEP) Q1 2011 Earnings Call May 10, 2011 9:00 AM ET

Operator

Ladies and gentlemen thank you for standing by and welcome to the EV Energy Partner’s Q1 2011 Earnings Conference. (Operator instructions.) I will now hand the conference over to Mr. John Walker, Chairman and CEO of EV Energy Partners. Please go ahead sir.

John Walker

Thank you. Good morning from Houston. EV Energy Partners Q1 for 2011 was very close to the mid point of our guidance. Production was adversely affected by some January and February weather in the Barnett Permian in Appalachia. The Mid-Continent was our star performer. The Barnett and Jamet in Eastern New Mexico were lagging production performers. Mark Houser will discuss the Barnett in more detail.

We’re pleased with our drilling and capital cost achievements in the Barnett, which are coming in about 10% below our AFE but production is not yet hitting our targets. I’ve asked Mike Mercer to adjust downwardly production guidance for the remainder of the year primarily related to the Barnett properties until our portfolio team has had adequate time to resolve a couple of issues that Mark will discuss.

General administrative expenses in Q1 got hit with some non-recurring costs, which are in our press release, but mike will discuss those. But rolling it all together, adjusted EBITDAX was right on the mid point of guidance.

I’d like to give you a key observation. Our balance sheet is in great shape after our $150 million equity offering in January. The $300 million 8% notes offering March and the new $1 billion five-year credit facility which was finalized in April. We had the financial capacity to easily do a $500 million acquisition and our stated goal is to do just that amount this year. We did $568 million, I believe, last year and so we think that we can at least repeat that.

We believe that the A&D market for oil deals is very overheated with Permian and (inaudible) deals being done at extremely low rates of return. Our focus remains in our core areas and long life reserves.

In Q1 we took the first loss in our history, $1.6 million, which is in the press release and this is the first loss in our company’s history when we sold some Oklahoma and Kansas marginal properties.

With the market overpaying for oil properties, we may sell another small oil field in Texas over the next few months. When the market goes on direction, we seek better values in the other direction.

As I mentioned in the past, we’re pleased with our Austin Chalk assets in Central Texas. We had mediocre drilling results last year but are having extremely good results this year. Historically we’ve spent 30% of cash flow there to keep the production flat.

Simple payout on all of our acquisitions that were done since 2007 is projected to occur at the end of next year and at that point in time reserves and value then will still be about what we pay for the acquisitions.

We’ve made positive progress in Utica including the course taken by us in our partnerships (inaudible) there have been nine wells into the Utica and it’s lower in (inaudible) then Point Pleasant. Information on the horizontal wells will be released this summer. EV has a positive position in this joint venture with Chesapeake; however, the preponderance of its acreage is held with EnerVest Fund 11 and will be developed or joint ventured separately.

We have a high regard for Chesapeake’s technical and functional skills but wanted to retain some acreage that’s separate from EnerVest’s very large joint venture with Chesapeake. The information in the Utica that we have to date is encouraging.

Overall I’m pleased with our team’s 2011 performance to date and believe that our goals for the year should be achieved. Now I’d like to turn it over to Mike Mercer who will give you some details about Q1.

Michael E. Mercer

Thank you John. For Q1 of 2011 our adjusted EBITDA was $50.6 million. That’s a 57% increase over Q1 of 2010 and a 22% sequential quarterly increase.

Distributable cash flow was $31.6 million as compared to our total distributions related to this Q1 of $29.5 million. That’s a 56% increase over Q1 of 2010 and an 18% increase over Q4 of 2010.

Production for the quarter was 7 Bcf of natural gas, 208,000 barrels of crude and 270,000 barrels of NGLs or 9.9 Bcfe and that’s a 69% increase over last year’s Q1 and a 19% quarter over quarter increase. Now these increases and adjusted EBITDAX, distributable cash flow and production were primarily attributable to our Appalachian, Mid-Continent and Barnett Shale acquisitions that we completed during 2010.

We reported a net loss for the quarter of $34 million or $1.14 per unit, however, included in the net loss were $54.6 million of non-cash unrealized losses on commodity and interest rate derivatives and $2.1 million of non-cash compensative related costs in G&A. It should be noted, and this is typical when commodity prices increase during a quarter, that the $54.6 million of non-cash unrealized losses on derivatives was primarily due to the increase in future commodity prices, oil and natural gas prices, that occurred from the beginning of the year through March 31st, the end of Q1. In the effect that this increase in prices has on the mark-to-market of our significant commodity hedge price derivatives it now runs through 2015.

Also included in G&A for the quarter was about $300,000 of acquisition related due diligence and transaction costs from our acquisitions and about $1 million of cash costs related to the vesting of phantom units. And this event occurs annually during Q1 of the year, the time at which our phantom units invest each year into common units.

We also had a very active quarter with regard to financing. We completed a common unit offering in our inaugural senior notes offering which combined, raised net proceeds of about $442 million. These proceeds were used to repay debt under our credit facility, which had been used initially to fund the closing of the Barnett Shale acquisition in December of 2010.

I’d also note that during April we completed a second amended and restated credit agreement with the same group of banks that we had in our credit agreement before. We’re very happy with our bank group that we have there and find them to be very supportive. It is a $1 billion five-year facility similar to the old facility but with improved pricing terms and with more flexibility provided with regard to commodity price hedging.

We have also, the last two points I want to mention are updated guidance, talk a little bit about that and an update on our hedging positions. You can see in the press release that we update guidance for the Q2 through Q4 of 2011. This includes a slight reduction in production estimates. If you look at the midpoint of the production guidance range for Q2 through Q4 of 2011 it now represents approximately 32.2 Bcfe of production for that nine-month period versus the prior midpoint of 32.8 Bcfe. So it’s not a large reduction; a slighted reduction of approximately 1.8%.

In addition, lease operating expenses and natural gas and NGO price differentials have been revised. And these two really offset each other on a cash flow basis. This is primarily to account for the treatment of certain gathering, transportation and processing expenses associated with the Barnett Shale acquisition, which we have presented as a product price or revenue deductions under the previously issued guidance rather than LOE. So the net effect of it is we’re revising our guidance up a little bit on LOE but we do expect, because of that, that our differentials relative to NYMEX prices on natural gas and on NGLs will be a little bit better. Approximately a 2% increase on natural gas and about a 1% increase on NGLs and those two will offset each other to bring the guidance in accordance with how it’s treated under GAAP.

We have also entered into some significant new hedges this year, primarily for 2014 and 2015. The commodity price hedge table that’s in the earnings release lists the hedges we entered into since the end of Q1 of this year and which are not included in the hedges that are listed in our 10-Q that we just filed last night. So if you add the ones in the press release to the hedges that are in the 10-Q, you kind of have an up to date view of the hedge portfolio as it stands today.

I’d also note that after our 2010 year-end earnings release but prior to the end of this last quarter, we added 20 million Mmbps per day of natural gas hedges at $5.55 for 2014 and $5.90 for 2015. Those hedges that I just mentioned are contained as part of the hedge disclosure in the 10-Q filed since they were done prior to the end of the quarter but didn’t want to note those that were done since our last press release.

I think that sums up my part of the comments. I’d now like to turn it over to Mark Houser to review our operational performance and expectations.

Mark A. Houser

Thanks Mike and good morning everyone. John has given an overview and Mike has described our financial performance last quarter and revised guidance for the remainder of the year so I’ll spend my time discussing our operational activities and capital plans for 2011 and as I did last quarter, I’ll finish with a bit more color on our interest position on the Utica.

Like most every other company reporting, our Q1 was impacted by the cold and snowy weather across most of the country. As it turned out, we came within approximately 1% of our guidance midpoint. I reported in February that our engineers estimated production was down about 2% for Q1 due to the three weeks or so of intense weather. That number turned out to be about right. The most significant loss was a two-week shut in of a Southern Union processing plant near our Galmut field out in the Permian Basin. And then thankfully in Mount Belleview with the enterprise explosion we were actually minimally impacted.

Mike also commented that our liquids production and revenues were higher as a percent of total revenues. These liquid revenues would likely have been even higher than that in the quarter but quite a bit of our Barnett gas bypassed the Crossett plant during the two cold weeks, reducing the amount of NDLs recovered from the gas.

We continue to believe that EVEP’s overall goal over time is to modestly grow production organically while leaving the dramatic growth to accretive acquisitions. We’re still requiring our 20% expected return on any capital project at current prices. That being said, our 2011 program is still expected to range between $65 million and $80 million. Our activity so far this year has been consistent with that base. This increase is mostly attributable from last year to our new Barnett and Mid-Continent acquisition. As we told you last time, about 75% of our total capital is being spent on drilling, about 14% on workovers and the balance on land and sizing. About half the drilling is occurring in the Barnett and the Austin Chalk and Mid-Continent areas each represent about 20%. That hasn’t’ changed. And in Appalachia we’ve now begun our Knox program and we also anticipate activity in the units that should heat up particularly late in the year.

First to our Barnett activities where EVEP has a 31% in the properties. We’ve now been operating the properties fully for a very quick four months. Starting March 13th we put a second rig in operations also in the liquid rich area and we now plan to drill around 45 to 47 wells. We have a full time frac crew and we’re very pleased, as John said, with our drilling and completion costs which are running about 2.1 million drilled and completed.

We’ve drilled 14 wells, six are on line and three more will be brought on line later this month. To balance the increase drilling for the year, we’re going to slow down some of our re-fracs to keep capital about where we want it.

I want to point out that production for the quarter in the Barnett including our weather downtime ran about $2 million a day below our expectations. Part of this variance is due to the timing of some of our completion operations. We’re zipper fracign these wells which is basically pumping multiple stages in three alternating offset well bores. To be more efficient, the well pad zipper frac eliminated moving frac equipment from well to well and also stores some of the frac energy in the reservoir for hopefully more alternate reserves. That’s been impacting our production rates somewhat. This more complex frac process is currently delaying some of our wells from coming on line as fast as we hoped, I should say as we originally budgeted.

Another variance is due to some of our adjacent existing wells being knocked offline for a period of time. Before they adjust and production is restored, the impact on offset wells from large fracs is normal and will not impact reserves over time but has impacted short-term production.

The beauty of our portfolio is that it’s very diverse. Our Mid-Continent assets continue to improve and were a stronger performer this quarter. Net production is running around 16.5 million a day in those areas. If you recall, I reported last quarter that it was between 15 million and 16 million a day. We’re mostly in a non-op situation in these properties but the operating companies are active including Sanguine and the Granite Wash and Cottage Grove and BP and the Woodford. Sheraton is very active in the fifth west fieldry development, most of the capital activity in the Mid-Continent I want to point out is oil or liquids rich gas.

Now moving to the chalk. We continue to benefit from favorable liquids pricing and performance. We currently have a two rig drilling program continuing both our ongoing naturally fractured horizontal program and our multi-stage frac program. We’ve drilled or reentered ten wells over the last few months and are on pace for about 18 wells this year. This chalk asset in our portfolio has been a great cash generator for EVEP. For several years now we’ve been spending about 30% to 40% of EBITDA while production levels have remained basically flat. We see the ability to do that for the extended future. As our production data on the multi-stage fracs is more later this year, we’ll give you more information on that and provide you with more detail.

Speaking briefly on Appalachia, the eastern division, despite the severe weather experienced no real surprises in our conventional production activities. We’re increasing our Knox activity this year starting out with approximately 100 square miles of 3-D seismic across some of our acreage in Ohio that was purchased in the EXCO and range transactions. On a net basis we’re planning to drill about 12 wells for EVEP compared to only two last year when we were kicking off the program. Drilling will start in the second half.

I’d like to point out that there’s some cost pressure particularly in rights-of-way, land and leases for our Knox wells as the Utica heats up. Speaking more broadly, the costs for EVEP were generally pleased with our controllable cost performance from our field operations despite pressures on fuel, chemicals, water holly and a few others, our teams have done a great job on controllables. Most of our cost increase that Mike discussed in field has been related to pumping services and to gathering and processing, which typically moved the price with commodity prices I should say.

So finally a few additional comments on the Utica Point Pleasant, which we will sometimes or a lot of times just call the Utica. Again, to remind you, we’ve been in Ohio operating production since 2001. We’re very familiar with the geology of the various reservoirs including the Utica. Our involvement in the assessment of the Utica is complex and thorough. So far we’re pleased with the progress on the technical side and look forward to the overall activity in this area over the next several months. And as John mentioned, we anticipate a bunch going on this summer, and being communicated this summer.

So generally to summarize, things are moving forward nicely. We made it through a pretty tough winter on our industry and are well integrated on all of our assets. We continue to focus mostly on production and cost surveillance while executing our development activities in the Barnett Chalk, Mid-Continent and Knox. We’re also very much on top of the current and future activities in the Utica.

So thanks for y’alls time and John, I’ll turn it back to you now.

John Walker

Okay. Thanks Mark. We will open for questions now.

Question-and-Answer Session

Operator

(Operator Instructions.) Your first question comes from Kevin Smith – Raymond James. Please go ahead.

Kevin Smith – Raymond James

Hi. Good morning gentlemen. You talked about your Barnett production being a little bit lower. From the prepared remarks it sounds like it’s more of a completion then actual well production. Is that accurate or did I miss something?

John Walker

Well let me talk about both pluses and negatives. The pluses, we’ve got a little rig out there that before we took this over, Tallon was drilling these wells somewhere in the 12 to 14 days. This rig has drilled the whole well in as little as seven days and I believe 15 hours and we’re consistently now running on an average between eight and nine days and we’ve reported plans to drill 36 wells and Mark, in his remarks, said that it would be 45 to 47 wells. So our drilling costs are coming in much better than expected and as I motioned, overall cost including the completion are running about 10% (inaudible) our AFE.

I think one of the major concerns has been we modeled that when we did these frac jobs and we put a lot of water, we modeled that we would knock some wells off but we had them recovering in a month to two months and it appears that the recovery, you k now, back to the former level of production, is really three to four months. And as a result, we’ve not adjusted our overall production has resulted in knocking wells offline. So it’s been the major issue and when, now we’re still early on this. We might be over reacting but I’d always rather highlight problems rather than surprise people with problems. And so that’s the reason that we reduced our guidance on production somewhat is because of that factor primarily. I’ll just add I’ve always pointed out every year that we’ve never had any kind of loss or impairment on our reserves and so I wanted to highlight, since I’ve always highlighted the fact that we haven’t had loss, that we did have our first loss and that was just getting rid of some marginal wells.

Kevin Smith – Raymond James

Okay. So I guess to follow up, do you expect your EURs to be any differently then what you were thinking or is it more just the timing of the production?

Mark Houser

The first ten wells that we have brought online have average IPs of about 2 million a day equivalent, which is basically what we expected. For the question in terms of EURs, we don’t have enough info yet to project these out and forecast exact EUR. Some of them are coming online and hanging in okay and some of them are declining a little faster than we would normally expect. But generally so far the IPs are suggesting that we’re about where we thought we’d be on that.

So what we’re basically meaning is right now as we bring these wells online, some of the problem is we’re simply, through our zip frac process and also just the fact that some of these wells as they’ve always done, they knock off other wells for a while, that’s a little bit broader of a band or a longer period of time as John mentioned then we thought. So I don’t have any bad news on the EURs at this point in time to convey.

Kevin Smith – Raymond James

Great. And then if I could switch gears and talk about the Austin Chalk; where are we in the multi-stage fracture well program? I mean are we far enough along to call it a success or are we still waiting for more well results?

Mark Houser

We’re waiting for a little bit more well results, I’ll say generally from a reserves perspective we’re starting to get more data. As I mentioned, we’ll report a little bit later this summer because we want a little bit more time to firm this up. But from a recovery perspective, the multi-stage steps seems to be working, we’re getting more out. It’s not dramatic but it’s good as we, I think conveyed, it’s good steady stable stuff for us.

Cost wise, a couple of the wells we tried to reenter just cost too much money reentering these wells but on wells where we’ve drilled new holes and then done multi stages, generally we’re pleased. So we’ll probably have three or four more wells by this summer that we’ll be able to report on and to me that’s getting to enough of a database to then say, here’s some results one way or the other on it.

John Walker

Yeah, we’re running tills on two different laterals right now and these are both Greenfield wells.

Kevin Smith – Raymond James

All right, thank you very much gentlemen.

Operator

Our next question comes from Adam (inaudible) from RBC Capital Market. Please go ahead.

Adam – RBC Capital Markets

Good morning gentlemen. You just answered a bunch of the Barnett questions. One more I guess. Liquids content still coming in as expected in the 30%-ish range?

John Walker

Yeah.

Adam – RBC Capital Markets

Okay. And then I’ll switch over to the acquisition side. You implied I think that you’re looking at gas properties. Is there any expectation of whether these would be new areas, bolt-ons or integration whether there’s some drop down opportunities and what kind of package sizes would you be looking at to get to $500 million?

John Walker

I think that, and Ron Gajdica is here and he may want to add to my comments. Of course we’re looking in our areas of concentration because we want to continue to build there. But we are looking at a package or two outside that. We do believe that there will be, soon, some very large packages of properties in some areas that I would think that along side top investments would be more likely. I don’t anticipate a drop down at least anytime in the next few months. The incisional funds don’t have any compelling need to drop down assets in a gas market where the starting price is in the low 4s.

Ronald Gajdica

Adam, just to finish up on your question regarding the size of deals that we would look at. Probably on the low side would be around (inaudible) million and the high side would be around $500 million or even higher if we were to partner with one of the intuitional.

Adam – RBC Capital Markets

Anything imminent?

Ronald Gajdica

We continue to look at several deals. We’ve got some offers in the works but nothing to report on.

Adam – RBC Capital Markets

Great. Thanks.

Operator

Your next question comes from Ethan Bellamy from Robert W. Baird. Please go ahead.

Ethan Bellamy – Robert W. Baird

Good morning gentlemen. Question on Ohio Utica. How much technology transfer or cooperation is there with Chesapeake with respect to the science there and completion techniques, etcetera?

John Walker

Well we’re partners. Before Chesapeake appeared on the scene we had gone through the Utica over 600 times (inaudible) predecessors in drilling Knox wells. So we had a lot of log information. We had actually cored the Utica again before Chesapeake came on to the scene and we provided them with our cores and then in partnership with Chesapeake we had done some cores. And so there is a lot of cooperation. I don’t think anyone would question the fact that Chesapeake from a technical standpoint is the leader in the industry in shales. And so whether it’s their core lab, their micro seismic, they do have a lot of information and they have been very cooperative in working with us and that’s the reason that we selected them as a partner for a westerly tract that we farmed out to them on July 1 of last year.

Ethan Bellamy – Robert W. Baird

Okay. You mentioned rights of way and leasing costs going up there, which is not surprising. Are you also seeing inflation on service costs in Ohio and could you maybe compare and contrast that with some service cost trends in other areas?

John Walker

I don’t think Ohio is any different from any of the other places. You know, the horizontal wells that are being drilled will be done with Chesapeake and there is rig availability for those rigs and I don’t think that Ohio’s experiencing anything extraordinary except that when we closed on the range deal March 30th of last year, the lease prices were $50 to $100 an acre and now they’re closer to $2500 an acre.

Mark Houser

Just on the more production operations side, you know, we’re seeing normal pressures on water hollying and some other costs that are fuel related as gasoline prices have gone up. But beyond that I think it’s too early to really judge. There’s not that much rig activity in Ohio right now related to the Utica quite yet although it’s starting to ramp up and we expect it to ramp up a good bit by this summer.

Ethan Bellamy – Robert W. Baird

Thanks Mark. Good luck gentlemen.

Operator

Your next question is from (inaudible 0:31:00). Please go ahead.

Unidentified Analyst

Good morning everyone. Quick question, I’m going to hit the third rail for a second. I’m just wondering if you could give any insight as to when a more normalized distribution policy and growth trajectory might transpire. And if there’s a significant equity raise within acquisition, would the GP be willing to give up some of the benefits of the IDRs in the short term to expedite that growth for the LPs?

John Walker

For sure the GP would be willing to do that if it ever hampered us in doing an acquisition. Obviously we’ve never had a problem with doing an acquisition and doing it at very tight (inaudible) PVs so that just hasn’t come into effect. But I think that we have communicated consistently that we’re not going to allow the IDRs to get in the way of a decent rate of return. We did not start growing the distribution last year because we were concerned about 13 and 14. We don’t have those same kinds of concerns now that we’ve just completed $568 million of acquisitions last year that were very accretive. At the same time we do have something major that we’re evaluating right now that’s going to have probably a very big impact on our assets and cash flow and so I think that, no, we probably will defer making a decision until that picture is a little bit more clear.

Unidentified Analyst

Okay. Thanks guys. Appreciate it.

Operator

Your next question is from Yves Siegel from Credit Suisse. Please go ahead.

Yves Siegel – Credit Suisse

Good morning. John, I’m not sure if it’s fair to say you’re evaluating something really big and then just dropping off like that. Can you elaborate a little bit on what you’re thinking is?

John Walker

Are you talking about my last comment in terms of (inaudible)

Yves Siegel – Credit Suisse

Yeah.

John Walker

Well it’s obviously the Utica. And the Utica has such a big potential impact on our overall assets, it would obviously impact tremendously the growth of our distribution. But I don’t like making decisions that are near-term decisions. I like being able, once we start the really restart any kind of meaningful growth in the distribution; I want to make sure that it’s foreseeable for the long term. I never want to have a distribution that we have to cut.

Yves Siegel – Credit Suisse

So as it relates to the Utica, the timing of making a decision, would it be sooner rather than waiting to get some more test results or more well results.

John Walker

Yves, as you know as well as I do, it’s one thing to have done all your work from the logs and have a lot of full barrel cores as well as sidewalk cores, which we have. It’s another thing to make sure that the oil and natural gas liquids, since we’re primarily in those windows, that they can move through these nanospaces and so the reason that we’re drilling these horizontal wells and we’ll be testing them will be so that we actually have confirmation that we’re going to get the flow rates that we would anticipate. So we don’t have the kind of information yet. It’s just going to take a few more months until we have that kind of information.

Yves Siegel – Credit Suisse

Okay.

Mark Houser

Yves, right now there’s at least three wells that have been drilled or are being drilled, some that we’re participating in within the EnerVest family, some that we’re not. But there may be more but that’s all going on. But there’s been no tests done on them yet and it’s getting closer. But hopefully this summer we’ll know more about production rates from those and then the decisions start being made.

John Walker

Well the other thing Eve is we’re partners in, and this is not necessarily EVEP but it’s true for EnerVest, we’re partners with Chesapeake in a large amount of acreage and what I want to do is be a good partner with Chesapeake and coordinate in terms of a release of information and so the key thing there is working with Aubrey and when they’re ready to make a statement we’ll be ready to make a statement.

Yves Siegel – Credit Suisse

Okay. And I’m sorry I missed it. So you think that might be three months from now or?

John Walker

It will be sometime this summer.

Yves Siegel – Credit Suisse

This summer. Okay, great. And I also just want to query in terms of the acquisition market looking a little exuberant, when you evaluate why you’re maybe even falling short in terms of winning a transaction, is it because of the PVs that are being put out there or is it a difference in analyzing the geology or do you think it’s a difference in terms of maybe folks using a different set of commodity assumptions?

John Walker

Well I think that you know, having been in this game for a long time, I guess much longer than any of our competitors in the acquisition business, we’re use to evaluating and making diffluent decisions in terms of our acquisition and so we have discount rates that we’re trying to achieve and if we can’t achieve those discount rates, we lose. And overall in the overall $1.5 billion at EnerVest, including EVEP bought last year, we were able to achieve those discount rates. But we probably, of all the deals we looked at, we probably lost somewhere between 80% and 90% of the deals we bid on. And so that’s the more typical situation. If you saw us wining everything that we work on, you’d absolutely know that we’re overpaying for it and we do have a frenzy over oil right now and people are frankly bidding double what we’d be wiling to do to achieve the rates of return that we want to achieve. And so when you have that kind of situation in the market, and I’ve seen it many times in the past, you have to go a different direction to achieve the rates of return and I found that if you‘re in this business over the long term, if you make good economic decisions every time you do an acquisition because I tell our folks we’re only as good as our last, you know, if you make a good decision every time then you’re ultimately going to do fine over time.

We’ve got to remember that EVEP probably has for this near term slash of the Utica, this is a very long term vehicle and everything that we’re doing is based upon achieving results over the long term.

Mark Houser

I guess when we’re looking at acquisitions I suspect that generally it’s not price, that the strip typically from what we can tell and from just talking to our peers in the industry, everyone kind of uses the strip at the time. There’s adjustments out years. But what I think what it boils down to is discount rate and then it’s also reserves. And by reserves it’s both evaluation of reserves, everybody, we do our own independent evaluation of reserves when we get a package. So there might be some discrepancies there between us and others. And the other part of that might be what others are willing to pay for in terms of the risk profile and whether they move into what would be considered probable possibles, whatever and we have certain standards on what we’ll be willing to do which might be different from theirs. So discount ate and reserve risk are projections.

John Walker

Yeah, you know, you’ve got PDP behind (inaudible) probables, possibles, and then you have IUDs Yves and that’s the imaginary undeveloped locations that some people seem to be paying for.

Yves Siegel – Credit Suisse

Okay. Just the last question for me. Have you moved the discount rate much given that your cost of capital has come down so much?

John Walker

No. I would say that if you look at our average discount rate that we’re able to buy things at last year, I’d say that it was somewhere in the 12% to 13% range on a PV basis that’s risk adjusted discounted.

Yves Siegel – Credit Suisse

Thanks guys and good luck with the Utica.

Operator

The next question comes from Michael Blum from Wells Fargo. Please go ahead.

Michael Blum – Wells Fargo

Thanks. Good morning. Most of my questions were asked. But just to clarify back to the acquisition market. So given your sort of thoughts on where we are and the A&D market being frothy. Would you expect you’re going to achieve fewer acquisitions this year then last year? I mean how should we think about kind of your targets?

Ron Gajdica

This is Ron. We are going to continue to be a disciplined acquirer of all in gas assets. And as opportunities present themselves we will act on those opportunities. We will be a participant, an anchor participant, but we’re not going to get over zealous on what we’re willing to offer and from time to time if we keep active in the Indy market we’ll win a few deals. But as John mentioned before, we’re going to lose about ten times more than we win. And we’re not going to overpay. We’re going to stay disciplined and we’re going to make good acquisitions that service well over the long term.

John Walker

I think that the market is somewhat frothy obviously on the shale deals and in oil deals. I don’t think it is necessarily frothy in terms of dry gas or in some instances assets that have gas and some natural gas liquids in them. So I don’t want my comments on the oil to make you think that the A&D market is overall frothy. We still believe that we’re going to at least succeed our goal of $500 million in acquisitions this year.

Michael Blum – Wells Fargo

Okay. Thank you.

Operator

Your next question comes from Stewart Starling from Private Investors. Please go ahead.

Steward Starling – Private Investor

Hello gentlemen, I’m more interested at the moment since I’m not an engineer in capacity, of the dividend. And I know the last time I spoke with you you said that you were trying to increase the dividend for every quarter. I know it’s been up fractionally and I just would, not that I’m unhappy with the way of the stock has grown; I’m very happy with that. But I’d like to know in the short term and the long term how you feel about that statement that the dividend should be increased and if not, how do you look at it? Will it stay at this level? Will it decrease? And any way that you can help me out I would appreciate it.

John Walker

I think that we’ve said that our goal is to increase the distribution 5% per year and that is over the long term. And I think I just previously said that since we’re facing a major event in the history of EV Energy Partners in terms of the quality of the Utica that we’ve made the decision to see how this plays out over the next few months before we make that longer term decision because it will be impactful in terms of our distribution. And our distribution obviously is one of the most important things that we do. The reason, and if you look at us versus anybody else, our compounded growth rate is over 16%. There’s no one else in double digits. We’re the only ones that have increased our distribution although as you use the word fractionally we’ve increased it fractionally over the last few quarters or several quarters. And so this is very, very important to us and I think the fact that so many of us around this room have bought shares in the open market, it’s a major part of our portfolio, it’s important to us also. But again, we want to make decisions that are good over the long term.

Steward Starling – Private Investor

Well I appreciate it. Don’t get me wrong. I appreciate the growth factor and planning for long term which is what I’m interested in. But thank you very much and just keep it going. I mean I bought it when it was over 9% and now the dividend is less than 6% so obviously the stock has grown in value much better than the dividend but the dividend is still an important part to me. So (inaudible).

Operator

Thank you (Operator instructions.) There are no further questions. Sir please continue with any other points you wish to write.

John Walker

Well thank you very much. We believe that we had a good quarter and we think that 2011 is going to be an important year in the life of EV Energy Partners and we appreciate all of you that are unit holders that are on this call and have been so supportive. Have a good day.

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