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

Q4 2009 Earnings Call Transcript

March 17, 2010 10:00 am ET

Executives

John B. Walker – Chairman and CEO

Mike Mercer – SVP and CFO

Mark Houser – President and COO

Analysts

Leo Mariani – RBC Capital Markets

Kevin Smith – Raymond James

James Sample [ph] – Hype [ph]

Michael Blum – Wells Fargo

William Adams – FAMCO

Carrie Bishop [ph]

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the EV Energy Partners fourth quarter and full-year 2009 earnings release 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)

The speakers for today’s conference will be John B. Walker, Chairman and CEO; Mark Houser, President, COO and Director; Mike Mercer, Senior VP and CFO; and Frederick Dwyer, Corporate Controller.

I would now like to turn the conference over to Mr. John B. Walker, Chairman and CEO. Please go ahead, sir.

John Walker

Good morning and thank you. This morning we do have an international call. I am in Mexico and Mark is in Costa Rica. So if we have any communications issues, Mike will take over for us.

EV Energy Partners fourth quarter and 2009 results were in line with our expectations. We did experience in December some freeze-out issues, which lowered production, particularly in the Appalachian Basin and the San Juan Basin. Mike Mercer will go into detail on all of our financial results, following me.

As a 2009 recap, we accomplished most of our objectives. Our diversified assets in eight basins provided reliable and very steady results. As one of the most hedged of all the upstream MLPs through 2014, we weathered the low gas pricing dollar last year generating over $77 million of hedge gains. I my opinion, the upstream MLPs are just much lower risk than that’s what’s in counterparts, the E&P C-Corps.

We increased our distribution modestly each quarter with a longer-term objective of growing our distribution at a faster rate in the future. Last year, we made three accretive acquisitions, and two of those were in the Chalk and one in Appalachian Basin. Along with these, we did two equity offerings to provide financing and reduce overall debt. Last year was a slow year for asset acquisitions, but 2010 appears to be much more favorable. I know the adversary shops [ph] are absolutely loaded with deals right now.

Using strip pricing, our reserve replacement cost was $1.36 per Mcf. In 2009, we had no impairments. Our overall reserves increased by 2.5% after – if you follow me here, after annual production, which was really 7.3% increase in reserves that was diminished by the 4.8% negative price impact.

We started 2009 with too much debt, $467 million. But by year end, we had debt of $302 million and a $465 million borrowing base. Obviously, with the new acquisition our borrowing base would be higher, but our debt will be somewhat higher. And of course, we did an equity offering raising $94 million about a month ago.

We announced the $152 million acquisition of 3,400 wells, 460,000 acres from Range which will close on March 30. Similar to the small EXCO deal done in November of last year, we paid a reasonable present value for the PDP, and that’s for the upside. In the Range deal, 42% of the revenues are from oil and 31% are oil reserves. Although, hundreds of offsite are in Clinton locations in both the EXCO and the Range deals, they do not meet our 20% risk-adjusted rate of return criteria to drill. And that’s really just because of lower gas prices and drilling and completion costs had just not actually gotten up yet.

More important, in both acquisitions, we picked up several hundred thousand acres that are in the fairway for the attractive Knox formation drilling even at today’s gas prices. EVEP’s parent EnerVest is the expert and by far the dominate participant in Knox drilling. Our expectation is that Knox production in 2013 and 2014 from the Range and EXCO deals will match or exceed that of the Clinton formation. Let me say that again, our expectation is that our Knox production in 2013 and 2014 from the Range and EXCO deals will match or exceed that of the Clinton formation, meaning we paid only (inaudible).

Let me tell you what I see for EVEP and to a certain extent the industry for 2010. I think it’s going to be a very difficult year for the gas market for the whole balance of the year. The most aggressive buyers of past year as examples, Chesapeake, XTO, EXCO are now thoroughly [ph] focused on shales that are selling their conventional gas assets. So we’ve lost our fearsome competitors and they’ve become our customers for assets; so striking an important element out of the purchasing part of the A&D market.

We are increasing our concentration of assets in places where we have dominance, such as Appalachia, the Austin Chalk and San Juan. Concentration allows us to continue to drive down costs and improve our marketing presence, meaning that for example in Ohio we have 100 million gross a day of production that becomes very attractive to (inaudible) and we can also buy capacity on pipelines if we need to.

You will see EVEP and EnerVest focus on concentrated operated assets so as to move our gas molecules in the more ample supplied markets in the future in my opinion.

Over 95% of EVEP’s 11,000 plus wells are operating and that’s very important in terms of controlling costs. If you don’t operate, you can’t control your costs. EnerVest will close its fund-12 [ph] for $1.5 billion beginning this month. And the reason I say this that size provides more alongside opportunities for EVEP. The four acquisitions that we’ve done in the last year or so have been alongside EnerVest and where appropriate dropdowns will occur in fund 12 over the longer term. But something I didn’t say last year, the problem will be dropdown opportunities this year from several EnerVest more mature funds.

I would also foresee further joint ventures and monetization of EVEP’s more risky exploration or shale assets this year. And I want to emphasis again that we will not drill well without hitting our 20% rate of return minimum. We are going to grow this entity through accretive acquisitions.

Now I would like to turn over the presentation to Mike Mercer and if you have questions, I will be standing by.

Mike Mercer

Thank you, John. For the full-year 2009, we had adjusted EBITDA $132.2 million which was 11% increase over the prior year and we had distributable cash flow of $75.5 million, which is a 20% increase over the prior year.

Our production for the year was 16.5 Bcfe and our net income for the year was $1.4 million. However, that did include $51.7 million of non-cash unrealized losses on our commodity hedges. As you remember, we do hedge quite a bit of our production all the way out into 2014, and with mark-to-market accounting that flows through our income statement every quarter, the non-cash unrealized portion.

For the fourth quarter of 2009, our adjusted EBITDA was $34.5 million, an 8% increase over the prior year’s quarter and 3% over the third quarter of ‘09. Our distributable cash flow increased 21.2% – or that was $21.2 million which is a 42% increase over 2008 and 9% over the fourth quarter of 2009. Our production for the quarter was a total of 6.2 Bcfe, which was a slight increase over ‘08 in the third quarter of ’09, and we did report on the book basis a net loss for the quarter of $2.5 million but that did include $17.3 million of non-cash unrealized hedge losses in it. So excluding those we would have reported a pretty substantial net income.

Our LOE for the quarter declined to $1.69 per Mcf, which continued to trend down for the year. Production taxes were $0.30 per Mcfe of production. And our cash G&A was about $0.69 per Mcfe; that was up a little bit over the prior quarters. Then in the fourth quarter, we had some due diligence cost on acquisitions which ran through the G&A line in just some year-end costs. We wouldn’t expect to average that going forward at that level on an annualized basis.

If I turn now to our reserves for the year; our year-end proved reserves, they were 365.6 Bcfe which is a 2% increase over 2008; that is 70% gas, 18% natural gas liquids and 12% crude. We were 93% proved developed producing and our PV-10 was $352.8 million.

Now if you look at the price that we used at year end, this of course was true for everyone this year. It was a gas price of $3.87 and oil about $61 a barrel. In using those year-end prices that clearly affects tail-end reserves.

We also presented in the press release what the reserves would have looked like to give you a more clear picture if we would have used the prices in effect at last year’s year end, and we also showed a case where we ran it at strip prices at the end of the year, basically we’re in strip prices for five years and held it constant thereafter. Using the prior year’s prices, the reserves would have gone up to 384 Bcf and using strip prices they would have been 441 Bcfe.

Our all-in reserve replacement costs were $1.67 for the year; however, that was, as I mentioned, substantially affected by the gas price utilized for these calculations declining from $5.71 per Mcf in year-end 2008 down to $3.87 this year. If we look at on a price neutral basis, i.e. pull out price revision effects, our all-in reserve replacement costs for the year would have been $1.4.

Now I am going to briefly turn to guidance for 2010; as you can see, we issued guidance for the first quarter and then for the final three quarters. The reason we have done that is because we expect the Range acquisition, which used to be a sizable acquisition, to close at the end of the first quarter. So we wanted to split them out and show it pre and post-acquisition.

For the first quarter, if you just look at, we show a range for all of these variables but if you just were looking at the midpoint of them, production for the first quarter, we were at little over 6 Bcfe, average daily production of about just under 67 million cubic feet a day, LOE about $10.5 million, production taxes about 5.5% of revenue on an un-hedged basis, and G&A of about $3.7 million with about $3.5 million for capital.

For the second through the fourth quarter, if you look at just a midpoint of the range, it is about 21.6 Bcfe of production which is just under 79 million cubic feet a day. Transportation margin of a little over $1 million; it is primarily from our Monroe assets. 35.5 million of LOE, 4.8% on producing taxes and midpoint estimate on the G&A of about $12 million, and about $21.5 million on CapEx for the second through the fourth quarter.

I think we also show at the end of the press release, I won’t discuss this, but we do show a hedge schedule that updates the hedges that we had in place as of yearend. We do expect that by the time we close Range that we will have substantially more hedges in place, and have been working on that since we announced it to cover our production out for three years or so, on those assets.

I would now like to turn it over to Mark Houser for a few comments on our operations for the quarter.

Mark Houser

Thanks Mike, and good morning. Operationally, our 2010 objectives remain consistent. We are just focusing in on maintaining or slightly growing our distributions through our existing operation, integrating our new acquisitions in Appalachia and continuing to pursue small incremental acquisitions around existing infrastructure. Of course, we are also continuing to pursue the larger acquisitions John described earlier. Our efforts to control and reduce operating expenses are continuing.

We had really good success with LOE being reduced 18% year over year to $1.71 in 2009.We will continue pushing on lowering costs, but we are somewhat concerned as we are seeing some trends in increasing service costs in some areas.

Production wise, our asset diversity has helped us through weather wise what has been a pretty tough first quarter. We had big snowfall and very cold temperatures impacting a lot of different areas just like everyone else and at all different times; but overall, we have continued to perform reasonably well.

In 2010, we will continue our capital activity under our minimum 20% hurdle rate. Capital spending from our existing assets – before our existing assets is projected to be over double last year or approximately $29 million to $30 million. This spending is primarily focused on drilling in the Chalk where we have two rigs running and will continue through all year, drilling two wells in the San Juan Basin including our first horizontal well in the Gallup formation and continuing some successful refrac activity we’ve had in the Chalk and the Jamet field in eastern New Mexico.

We have begun our integration of the EXCO Ohio acquisition and continued to move forward towards closing on the Range transaction. We closed the EXCO transaction in November and hope close Range later this month. And as John mentioned earlier, one of the key elements to these acquisitions is our increased position in the Knox series of reservoirs primarily in eastern Ohio. EV and other EnerVest partnerships now control over 1.4 million acres in this play.

EnerVest and EV combined will be drilling 58 wells, that’s about eight wells for EV this year and then ramping up further in 2011. Just want to remind you all these are very high rate of return wells. They are typically cost drill and complete around 600,000 and with IPs averaging around 400 million a day, sometimes they can be quite oily with and EUR average of around 450 million cubic feet a day. So we are very excited. Again, we are obviously still formulating our plans on the Knox as we integrate the Range transaction though we anticipate that beginning to drill around May.

So that’s all I have. I would like to turn it back over to John.

John Walker

I don’t have more insights. I think Mark you said 450 million a day, I think you meant 450 million in reserves.

Are there any questions?

Question-and-Answer Session

Operator

(Operator instructions) And our first question is from the line of Leo Mariani with RBC Capital Markets. Please go ahead.

Leo Mariani – RBC Capital Markets

Hi, good morning guys.

Mark Houser

Hi, Leo.

Leo Mariani – RBC Capital Markets

I was hoping you guys could better clarify how much production downtime you think you got in the first quarter here?

Mark Houser

My view, you have some information on that but we are still – you want to elaborate on that. I am not – you are probably in a better position to describe that right now.

Mike Mercer

Leo, we don’t have sum of exactly how much we have been impacted, you know we added up in all the areas for the first quarter.

Leo Mariani – RBC Capital Markets

Okay. But it sounds like – it sounds like it was pretty significant, I guess it hit you guys in Appalachia or any other areas that used to be –

Mike Mercer

It is probably –

Mark Houser

Leo, it might be in the ballpark of – but not more than 5%. It is not double-digit effect.

Leo Mariani – RBC Capital Markets

Okay, it sounds good.

John Walker

Let me clarify. We had – for example, we said we had the two really cold weeks. It affected during that period of time, which is some of that on the quarter but it is fairly minor if you look at the overall quarter. But then probably in January and February, we had some of the same effect. So I would agree with Mark, it probably 5%, but the industry lost an estimated 3.5 billion cubic feet a day during that period of time.

Leo Mariani – RBC Capital Markets

Okay. In respect to your activity in San Juan, you talked about drilling a horizontal well. What do you guys looking at out there that has got you excited about drilling your first horizontal?

Mark Houser

Well, we have for the Gallup formation and actually a couple other conventional Macy Bird [ph] and other formations that we have some initial plan to drill as well as this Gallup which in Bear Canyon area in our San Juan assets within EVEP. And again it is somewhat repeatable as it works. It has got some oil potential to it and it has been something we have been planning to drill, and frankly pushing cost to get it where we wanted to. And we have gotten some pretty good bids now on how to get it drilled and we are working and moving forward on it. So we will kind of see how it goes Leo, but it is kind of down a fairway, and we are excited about that.

Leo Mariani – RBC Capital Markets

All right. It sounds like you are spending the majority of money in the Chalk. Is that going to be fair bit more on the oily and liquid zones there?

Mark Houser

We really don’t play it that way in terms of oil and liquids. We just look for where we are really seeing the best in fracture trends and really been able to predict the fracture trends. And right now we have been a little bit in oilier window, although that we kind of move around as the geologists find additional opportunity. So there is no direct focus on playing the oiler window Leo. It just really depends on what the geologists are seeing.

Leo Mariani – RBC Capital Markets

Okay. And I guess it sounds like you guys are continuing to see a lot of deal flow in your core areas here. And it sounds like kind of competition for some incremental assets has dropped off. Do you guys have any – is there any sort of thought on kind of potential target for deals? Did you guys not look at it that way in terms of dollar amounts?

John Walker

Let me comment on that because I was one that maybe just talked about. We have lost the guys that were so aggressive in the past, particular Chesapeake with XTO. But we are seeing some new interests that are a little bit scary, and I am not sure they know what to do and those are some of the really big funds that have move in, some of the big hedge funds and private equity funds. So I think we will probably see some announcements, but some of that – we have already seen one. They have been extremely aggressive, but I guess the good news there is they will overpay and they don’t know what to do. They will allow us to buy those assets a year or two or three down the road for a more reasonable price.

Leo Mariani – RBC Capital Markets

Okay. It is helpful guys. Thanks for your time.

Mark Houser

Leo, one more comment, it is Mark, just relating to your production question. As an example, I am looking at one of our weekly reports for our Appalachia assets and we are off less than 2% in terms of our production relative to what we had originally planned which again isn’t exactly where, it is kind of in the mid of guidance. So we are – that’s kind of the impact we are seeing. So I just want to just point out, we are seeing some impact but as I made the point because of our diversification we are not getting hit by any one area badly but we are getting hit a little bit in different areas. So hopefully that gives you a little bit of perspective on what we are seeing right now.

Leo Mariani – RBC Capital Markets

Definitely helpful.

Operator

Thank you. And our next question is from the line of Kevin Smith with Raymond James. Please go ahead.

Kevin Smith – Raymond James

Good morning, gentlemen.

John Walker

Good morning.

Kevin Smith – Raymond James

Hi John, you mentioned some funds might be willing to start monetizing some properties this year in EnerVest funds. Can you give me I guess any more flavor on that, and what type of properties we are looking at and maybe in what areas?

John Walker

Of course, we have to go through a process of our independent directors on the board of EVEP agreeing to make an offer, and then the funds themselves will go through the process of approving it. But we did have some mature funds that we will be showing, so and I think you should anticipate that since our focus is increasing our pricing, Appalachia, Chalk, San Juan, in some of those areas. Those are areas of greatest concentration.

Kevin Smith – Raymond James

Okay, fair enough. And what’s going to be a break out between drilling CapEx versus workover and completions?

Mark Houser

Drilling – and let me pull that number real quick for you. But in total, drilling and workover is around 29.9, if I recall, and again I am not having the sheet right in from of me. I think that drilling is about 27 of that.

John Walker

But I want to also emphasize that in November when we lay out our drilling budgets for the following year, we had a gas price that was higher than what we are currently experiencing, even higher than probably what we are going to experience. And therefore, some of our plans will not be realized if we don’t hit the 20% rate of return. And I would say that I don’t have a percentage in front of me but some of those wells don’t hit the 20% right now. And we are just not going waste money, and you are clearly wasting people out there drilling right now for no return, negative return. And you’re just not going to see that happen with us.

Mike Mercer

Kevin, it is probably about 10% in the work over.

Kevin Smith - Raymond James

Okay, thank you very much and that logic makes a lot of sense. And one last question, where do you feel – why do you think the Chalks still make sense and where is kind of your hurdle rates on gas price and oil price?

Mark Houser

The Chalk makes sense down to getting into the $4 gas range. Again even on some of the dry well, there is still some liquid content and with just the kind of initial rates we get off most of our wells, and again not every well works, but generally we are seeing still some 20% hurdles down into the $4 window.

Kevin Smith – Raymond James

Okay. Thank you very much.

John Walker

Well, let me also add. The Chalk wells are not fracs when we initially complete them, because they have so much pressure. We are going back into some of the older wells and spending money there and we are getting extremely good results. And I will remind everyone, we have 1,700 well bores out there, and so there is plenty of reentry opportunities and there is plenty of refracing opportunities. So many of these laterals would refraced for the first time this year.

Kevin Smith – Raymond James

All right. Thank you.

Operator

Thank you. And our next question is from the line of James Sample [ph] with Hype [ph]. Please go ahead.

James Sample – Hype

Hi, you mentioned in your opening remarks that – you told that the E&P, MLPs were considerably less risky than C-Corps. Could you elaborate a little on that please?

John Walker

Yes, I just mentioned one of the reasons that I think so – I think there might be and I think major players [ph] in the upstream business are just more responsible in terms of how we spend our capital. And so we are not going to go out and drill wells just to drill and waste money. The other thing is that we are so much more hedged. And I think if you look at the results of late 2008 through 2009, I think the major players in upstream business showed that not only are we going to survive, which was a big question, but we are going to do pretty well. And I think that you will continue to see that. And I think that our sector of the business is focused on rate of return. I am not always convinced with the E&P, C-Corps are concerned about rate of return as much as they are in same play increasing production whatever the rate of return.

James Sample – Hype

As a follow up, though, as unit-holders here, we are extremely sensitive to any potential cut in distribution. And regardless of what might be going underlying, the E&P MLP cuts its distribution that’s it for the unit price, whereas the C-Corps seemed to have much more flexibility in not having a single event that would cause their stock to tumble.

Mark Houser

Well, I guess I will respond to that. I think that the fact that you look at upstream MLPs, you look at the kinds of assets that we own, you look at the way we’re capitalized, you look at the way most of us go out and hedge, and the volumes that we hedge and the length of time we hedge all of that, the asset mix, the leverage, the hedging, the low decline rates and the base production is all built around the model of time to minimize the risk that distributions – or to maximize so the probability of distributions stay flat or go up over time.

James Sample – Hype

Okay, fair enough.

Operator

Thank you. (Operator instructions) And our nest question is from the line of Michael Blum with Wells Fargo. Please go ahead.

Michael Blum – Wells Fargo

Hi, good morning everyone.

John Walker

Hi, Michael.

Michael Blum – Wells Fargo

Hi, just a couple of follow ups to those. One, the same question was asked on the Chalk. I would ask that question about Appalachia, where do gas prices need to be to get an appropriate return to start drilling there?

Mark Houser

Michael, it is Mark, and there are two different drilling opportunities we have. One is kind of our conventional Clinton-type drilling, and again we never valued anything in an acquisition to include any sort of new Bonnie [ph] shale type Clinton drilling. Those were probably looking at $6 an M to have those sustained program now, because of our size now with the number of wells we have in Appalachia. We are going to have much more opportunity to work with service providers to negotiate terms so we can commit to a significant drilling program with them at the appropriate return. Now that is on our Clinton side which is again not something we had planned on.

Now the other side is on the Knox. And the Knox is again where we have drilled well over I think it is a 128 wells so far over the last five years amongst the EnerVest family, has had great results and doing it at very high rate of return. And in those wells, again we can justify drilling down into the $4 strip range based on our current cost even which we have seen again on conventional drilling, not necessarily some of the horizontal Marcellus type, but we have been some of the older rigs, we have been able to in that area to get cost or keep cost down into the kind of the 600,000 drilling complete which makes it very viable even at $4 an M. So that’s an area that we plan, as John mentioned and I mentioned, we plan on continuing to grow over time and we will have a significant impact over time on our production volume within Knox [ph].

Michael Blum – Wells Fargo

Okay. John mentioned that you may be looking at monetizing some of your, I think he said riskier or shale type assets. Can you talk about what you have in mind there and how meaningful could that be in terms of a total number of divesture?

Mark Houser

Well, I think in total we have around, I believe it’s around 4,000 or so remaining Marcellus shale acres within West Virginia and a smalls-mattering [ph] other places, but very small. That’s a ballpark number Michael. And as part of a larger package, we’ve actually contacted several folks in industry about the potential for some sort of a monetization or JV and that’s really kind of in progress, and so stay-tuned. But we are – again we had put out kind of a formal bid process and we’re – I would say, formal – a solicitation of offers which we are starting to receive some offer, and we are not at a point yet to talk about anything, but we are on our way. But it would be towards some sort of a monetization.

Michael Blum – Wells Fargo

Okay. And my last question was just how should we think about your capital budget for 2010. We’re just having our chances of shifting the numbers. But how much of that would be maintenance or to maintain production versus grow production?

Mike Mercer

Michael, as you remember, we don’t actually split drilling dollars up into maintenance or gross drilling. We have a separate concept for estimated maintenance capital, which is the amount that we think over time is necessary to maintain our reserves and production over the long term. And we could maintain our assets either by acquiring assets or by drilling and finding more opportunities expanding the prove base. So we don’t really split up our budget for the year into maintenance drilling and gross drilling or maintenance acquisitions and growth acquisitions.

We have an estimate of how much we think we need to set aside a reserve to maintain the asset base, but it can come from drilling or acquisitions.

Michael Blum – Wells Fargo

Okay. Thank you.

Mark Houser

And Michael, just to that end based on our current – again, we are closing on the Range transaction and our budgeting to the point that we had put things together were we get the $30 million of capital was tied to everything excluding Range, which again we’re still kind of formulating our final numbers on what we will be drilling in Range. But based on that which is our 29, and obviously less than projections of the dollars distributions. We feel like we will be able to exit the year at a slightly higher rate than we are entering.

Michael Blum – Wells Fargo

Thanks Mark. It’s very helpful.

Operator

Thank you. (Operator instructions) And our next question is from the line of William Adams from FAMCO. Please go ahead.

William Adams – FAMCO

Hi, good morning guys.

John Walker

Hi, Bill.

William Adams – FAMCO

Mark, you mentioned that the oil service costs might have been certain to creep up. Can you give us a little more color as to the magnitude of the increase and maybe what region of the country you are seeing the biggest there?

Mark Houser

Well, just generally, Bill, I think if you in reading lately you know that rig utilization has climbed dramatically. I think it’s over 1,400 rigs now and it was more than 800 in the trough period. And with that you are seeing a lot of pressure on costs, some on rig utilization, some on rig rate, a good bid on pressure pumping and other frac services. There is some pressure there. We are not as directly impacted as others are because we are just not active in the shale. That being the case as the shale area has continued to stay very busy, the service guys made some pretty big adjustment last year, and in terms of their staffing and all. And so it does put some pressure on overall availability of equipment and people.

That being the case, again, a lot of the areas we are in as an example, Ohio and as an example the San Juan, even the Chalk are not areas where there is a lot of the feverish shale activity. And so we are probably feeling a little bit less than most, but we hear in our – we hear talk from our service providers and our guys are having a constantly push back. And so just because you are hearing about activities going up in another area of the country, I don’t think that has necessarily something to do with that cost. So it’s just a constant battle.

William Adams – FAMCO

Okay. And then –

John Walker

(inaudible) Bill. Again, just because of the concentration, the ability to get our rates of return to drill barely be thousands of wells in the Appalachian Basin. We do have the opportunity because some of these service companies say, “We will guarantee 300 wells if you can get the cost down to a certain level,” and so again, that’s another benefit of concentration.

William Adams – FAMCO

Right. And John, I know you want to reiterate your point about the Knox formation, the returns. And I think you are cutting out when you –

John Walker

Yes, I apologize to my communications that unfortunately are not great here. But, well, we have a lot of experience from the Knox and we are the experts and it is just a very high rate of return area where we have a record and expectation is that we will continue to generate very high rates of return there.

I think that Mark has mentioned 600,000 co-ops. I think that we will be able to drive that down as we move from drilling 30 wells a year to 150.

William Adams – FAMCO

Okay. And you mentioned that Utah production by 2013 or ’12 or ’13 would be exceeding your production from the Clinton formation.

John Walker

Yes, we do expect that.

William Adams – FAMCO

And what’s your production right now from the Clinton?

Mark Houser

Well, basically the production stated in the Range and EXCO transaction is essentially all Clinton.

William Adams – FAMCO

Okay, and then –

John Walker

Yes, I think from those two overall, I can’t break it down because we only took a small piece of the EXCO, $25 million of the $145 million deal, but EXCO is producing about 14 million a day. And in the Range deal, it’s producing 22 million, 23 million a day and we have 46% of that. The net to EVEP on those two productions is about 13 million in that ballpark.

William Adams – FAMCO

Okay. So that’s why you will be exceeding from the Knox then?

John Walker

Yes. But that’s pretty – again we are very focused on 13 and 14. And because we are so well hedged through 12, our focus is buying things and attract the market that takes us – will grow in 13 and 14 relative to 12.

William Adams – FAMCO

Okay. And I was just going to ask you Mike on the finding cost calculation you gave us, I thought you said that it looks like you had a positive revision for the year in 2009.

Mike Mercer

Right.

William Adams – FAMCO

Okay.

Mark Houser

If you just look at the numbers in our K, which is year-end ’08, year-end ’09 and look at all-in reserve replacement, it was about a $1.67. If you look at – but that’s you know the year-end ’08 we used a gas price of $5.71, this year we used $3.87. If you look at it on a price neutral basis, in other words, if you ran the numbers using the same price in both, end of last year and – end of ‘08 and end of ’09, it would be about a $1.4.

William Adams – FAMCO

Okay. Okay, great. That’s all I have. Thanks so much.

Mike Mercer

So which is clearly also I would note we deducted this past year $1.35 to $1.40 on our estimated maintenance capital. And if you look at it and we think it’s appropriate to look at it on a price neutral basis. It was about $1.4. That kind of hits on point that we’ve always believe that it’s not just the cost this year to maintain reserves and production. It’s over the long term.

William Adams – FAMCO

And would you think going forward you are going to still be at that $1.35 or $1.40, or what your –?

Mike Mercer

Our board looks at it. We look at it every quarter and review it. So we wouldn’t want to make a projection on where that’s going to go. But we look at that on a quarterly basis.

William Adams – FAMCO

Okay, great.

Mike Mercer

Thank you, Bill.

Operator

Thank you. And our next question is from the line of Carrie Bishop [ph]. Please go ahead.

Carrie Bishop

Yes, correct me if I am wrong. But when you did the opening statement I think you mentioned that you are expecting the distributions to be reduced, if I was correct, and could you explain on it a little bit?

Mike Mercer

I think –

John Walker

Go ahead Mike.

Mike Mercer

Well, I was going to say I don’t think that John did mention that he expected them to be reduced. I think he had stated that you know we’ve been modestly increasing them every quarter. And it’s our goal at some point here in the future to raise them more to have more than a modest increase.

John Walker

He said if we’ve grown our distributions faster than any of the other MLPs in, obviously it’s important for us to continue to grow them. So I didn’t say that.

Carrie Bishop

Okay, I am sorry. I miss heard that, I thought I heard it. So I thought I would better clarify that.

John Walker

Yes, thank you.

Carrie Bishop

Okay, thanks.

Operator

Thank you. And there are no further questions at this time. Please continue.

John Walker

Okay. Well, thank you for joining us on the call this morning. And I apologize for some of our communication disruption. We look forward to a great year in acquisitions for EVEP and look forward to working with you. Now that we are participating in the dominant factors in Austin Chalk and the Knox formation that many of the others are not exposed to from other companies and we recognize that we need to have a gathering of analysts and investors to deal-with both of these areas in detail and we are making plans to do that right now. But we look forward to this year and the future. Thank you.

Operator

Ladies and gentlemen, this concludes the EV Energy Partners fourth quarter and full-year 2009 earnings release conference call. You may now disconnect. Thank you for using ACT Conferencing.

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Source: EV Energy Partners, L.P. Q4 2009 Earnings Call Transcript
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