EV Energy Partners' CEO Discusses Q4 2011 Results - Earnings Call Transcript

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EV Energy Partners (NASDAQ:EVEP-OLD) Q4 2011 Earnings Call February 29, 2012 5:00 PM ET


John Walker - Executive Chairman

Mark Houser - President and CEO

Michael Mercer - SVP and CFO


Kevin Smith – Raymond James

Ethan Bellamy – Robert W. Baird

[Tony Langham - Corey Partnerships]

Adam Leight – RBC Capital


Good day ladies and gentlemen. Thank you for standing by. Welcome to the EV Energy Partners fourth quarter and full year 2011 earnings conference call. [Operator instructions.] I would now like to turn the conference over to Mr. John Walker, executive chairman. Please go ahead sir.

John Walker

Thank you. I’m calling from Houston’s Intercontinental Airport while the rest of our team is in EVEP’s offices in Houston. Mike Mercer will elaborate on our financial results, but results were generally in line with guidance except for G&A expense, and I want to explain that.

On approximately $450 million of acquisitions in the fourth quarter, we recognized $2.3 million of due diligence and transaction related costs that flowed through to both EBITDA as well as distributable income.

Also, we recognized roughly a $4 million impairment charge on some noncore Austin properties that are going to be sold later this quarter. And that’s offset by the $4 million we received from Total and [unintelligible] from the sale of the assets in the Point Pleasant Utica NGL window.

Also, based upon successful efforts accounting, we had $9 million in dry hole costs, and that was primarily from the two horizontal wells that we drilled in the San Juan Basin. We continue to do a very good job of dropping our per-unit LOE costs. In 2010 these were $1.92 per Mcf equivalent, and we dropped those to $1.81 in 2011 and for the fourth quarter it was $1.78. We continue to expect to drive down costs in 2012. Our replacement costs were $1.43 last year and our acquisition costs were $1.21 per Mcf equivalent.

Our acquisition strategy of basin concentration allows us to continue to lower costs in a difficult natural gas and ethane market. Based on expected production, EVEP is about 90% hedged in natural gas, NGLs, and oils this year and 80% next year.

I decided to reorganize EnerVest, the GP, of EVEP in December of last year. Three of our entities, EVEP, EnerVest Institutional GP, and EnerVest [unintelligible] and the leaders named as CEO of those units including Mark Houser of EVEP.

The organization was needed as a result of the $3 billion in acquisition growth EnerVest entities have had within the last two years, and the further need to get even more focused on our assets. My role as CEO of EnerVest has not changed.

A few weeks ago, EVEP completed a 4 million share offering including the [sole] overallotment option for $268 million net to the company to provide a stable and conservative balance sheet. The offering was roughly three-times oversubscribed from both retail and institutional investors and obviously we’re very pleased with that.

In the Utica, EnerVest entities have participated with Chesapeake in 27 wells and have 5 producing. I want to particularly highlight the Burgett well, which had higher condensate yields than all the previous producing wells and we’re also pleased with how well the Burgett well is holding up.

We’re encouraged that the completion process in the NGL window is significantly improving and costs and days to drill are coming down. EnerVest Operating is drilling its first Utica well, the Frank 2H for EVEP and [Fund] 11 in Stark County to address, along with Chesapeake and other operators, the best completion technique for the oil window, and we still plan to commence the monetization process for our Utica assets later in the second quarter.

Now Mike Mercer will go over our financials, guidance, and [unintelligible].

Mike Mercer

Thank you John. For 2011 our adjusted EBITDA and distributable cash flow were $212 million and $126 million respectively, which were increases of 43% and 34% over 2010. These increases were primarily due to acquisitions completed during the fourth quarters of 2010 and 2011. Distributions related to 2011 were approximately $118 million.

Production for the year was 29.2 Bcf of natural gas, 891,000 barrels of crude oil, and 1.096 million barrels of natural gas liquids, or 41.2 Bcfe. This is a 47% increase over 2010 production of 27.9 Bcfe and, once again, it was primarily due to acquisitions we completed during the fourth quarters of 2010 and 2011.

2011 net income was $102.6 million, or $2.71 and $2.68 per basic and diluted weighted average LP unit outstanding, respectively. Several items to note that were included in that income for the year were $35.5 million of unrealized gains on commodity and interest rate derivatives, primarily due to the decrease in future natural gas prices that occurred from the end of 2010 to the end of 2011, and the effect of such prices on the mark-to-market value of our outstanding derivative portfolio.

$9.8 million of noncash compensation related costs contained in G&A expense. $2.9 million of property acquisition due diligence and transaction-related costs for the acquisitions we did in 2011 and a little bit of tail over from 2010 acquisitions. $12.1 million of dry hole and exploration costs for the year. $11 million of impairment costs, primarily that related to the divestiture of noncore oil and gas properties and assets held for sale at the end of the year, and a $4 million gain on the sale of assets related to a small amount of our Utica acreage that was part of the Chesapeake and Total agreement completed in December 2011.

For the fourth quarter of this year, adjusted EBITDA was $54.5 million, which is a 31% increase over the fourth quarter of 2010, once again primarily due to the acquisitions we completed during the fourth quarter of 2010, and a 4% increase over the third quarter of 2011. Distributable cash flow for the fourth quarter was $30.8 million, 15% over the fourth quarter of 2010 and flat versus the third quarter of 2011. Distributions paid for the fourth quarter or related to the fourth quarter, which were paid on February 14, were $29.8 million.

For the fourth quarter, production was 8.1 Bcf of natural gas, 235,000 barrels of crude, and 269,000 barrels of NGLs or 11.1 Bcfe. This is a 34% increase from the prior year’s fourth quarter production of 8.3 Bcf, once again due to our acquisition activity, and a 10% increase over the third quarter production of 10.1 Bcfe.

Fourth quarter net income was $9.7 million, or $0.27 per basic and diluted weighted average unit outstanding. Several items to note were $2.3 million of unrealized gains on our commodity and interest rate derivatives. There was quite a large decrease in future natural gas prices that occurred from the end of the third quarter to the end of the fourth quarter, but that effect was significantly offset by changes in crude oil prices during the quarter, an increase in crude oil prices.

$10.5 million of dry hole and exploration cost. As John had mentioned, about $9 million of that was related to two wells in the San Juan that we [D&Aed]. $4.4 million of impairment cost related to the noncore Austin Chalk assets John mentioned we’re holding for sale, which we’ll sell this quarter. The $4 million gain on the Utica assets that we previously discussed. $3.2 million of noncash compensation costs contained in G&A, and the $2.3 million of property acquisition and due diligence and transaction related cost, which were related to the almost $500 million of acquisitions we announced and completed in the last half of 2011.

Now I’ll turn to guidance. As you can see, we put out guidance for each quarter for 2012 and a summary for the whole year. I won’t go through each guidance item by quarter, but I’ll just hit a couple of the highlights.

The production guidance range for the year is 154.4 to 170.4 Mmcfe per day. Expected production in the first quarter is slightly impacted by the fact that we did have a small part of the Encana Barnett acquisition, which didn’t close initially in December, but did finally close, as we had noted in a recent 8-K, during February of this year. So we’ll have part of that production for that final piece of the asset for part of the first quarter, but then for the remainder of the year.

Production is expected to grow through the year, with fourth quarter guidance range averaging approximately 8.5% higher than the production range for the first quarter of the year. Natural gas and crude oil price differential ranges versus Nimex are 96-103% on natural gas and 91-97% on crude oil.

We have a net transportation margin range on third-party transported volumes of $1.2 to $1.4 million. The guidance range for LOE, which includes gathering and transportation costs, is $101-$113 million. Production tax as a percentage of revenue, between 4% and 4.4% of revenue. Cash G&A expense, which is typical with our guidance.

We do not include any potential acquisition or possible acquisition related due diligence and transaction costs, as we don’t have any right now that we have announced but haven’t closed on. That cash G&A expense range is $23.6 million to $26.4 million, with a slightly higher relative amount in the first quarter. That’s typical for us in the first quarter of the year due to the cash costs that we have related to annual restricted unit investing that we have occurring in January of each year.

Capital expenditure range is $140-180 million, which does not include any amounts for any potential acquisitions of oil and gas properties.

Now I’d like to turn to our hedge position. At the end of the earnings release, we’ve highlighted our natural gas, NGL and crude oil hedges that we entered into since the end of 2011. We also, in a subsequent table, fold those in with the hedges that we had a year in, and it shows you our full hedge position that we now have as of the end of February.

Now, during December and the beginning of January, we did have a significant amount of hedging of natural gas, NGLs, and crude oil. The ones we added in December were more related to the acquisitions that we closed in December, significantly in the Barnett Shale acquisitions. But then at the beginning of the year, in January, we added quite a bit more hedges, natural gas and crude oil.

Now, most of these hedges that we added, there were some in 2014, but we added significantly to our hedge position in 2012 and 2013, so that, as John had earlier mentioned, we’re now approximately 90% hedged for 2012 and 80% hedged on expected production for 2013. So we have significantly mitigated - not eliminated, but mitigated - commodity price volatility from our potential results, all other things being held equal.

The last thing I’d like to note is that subsequent to the equity offering that we completed a few weeks ago, the debt under our credit facility was reduced. It is now at $420 million. What I’d like to do now is turn it over to Mark Houser to review our operations for the quarter and discuss a little bit of what our plans are for 2012.

Mark Houser

Thank you Mike, and good afternoon everybody. I’ll start with our year end proved reserves. At the end of last year, our 2010 SEC reserves were 817 Bcf equivalent, and through 2011 we’re now at 1.14 Bcf equivalent. That’s an increase of 327 Bs, or 40% for the year.

Our reserves are now 71% natural gas, 21% natural gas liquids, and 8% oil, and the reserves are 68% proved developed. Acquisitions accounted for about 380 Bcf of equivalent proved reserve additions in 2011 and divestments were 6. We have revisions and additions of -5, and production was 41 Bcf, as Mike had mentioned. So our all-in reserve replacement cost was around $143 per Mcf equivalent, and acquisitions, which accounted for most of our reserve additions, were made at a cost of about $1.20 per Mcf equivalent.

So, in summary, we’ve increased our reserves significantly during 2011, including a strong undeveloped position with a good liquids content in the Barnett and it’s mostly held by production in nature, and therefore we can throttle up or down activity depending on what commodity prices and costs are doing. And we’ve done all this at a low unit cost.

Our challenge now, our task, is to manage our portfolio. We’d like to be, over time, more around 80% PDP, so as we do acquisitions, particularly later this year, you’ll probably see us ramp that back up toward a more 80% type level.

Now, if I go to production and LOE, that’s already been spoken to a bit, but when I spoke to you last quarter, we had experienced some delays in bringing Barnett and Chalk wells online in the third quarter, and that had kept production at the low end of guidance. But I mentioned we were making progress late in the quarter. Some of that came to pass, and indeed we showed a good increase in production from the third to fourth quarter, and we fell within our range of guidance.

We’re still experiencing some line pressure problem issues in the Barnett, and it’s not just tied to the Barnett. Our first looping project reduced our back pressure in the Barnett, and we experienced about a million cubic feet a day rate gain there, and we have several other looping and compression projects in the area. We’re also continuing to work with the midstream folks to help bring these out over time and give us more capacity.

We had a really good quarter in controlling lease operating expenses. It ended up near the low end of the guidance. That’s a real credit to our guys in the field, who are also busy integrating our new acquisitions. The full year average unit cost declined by $0.11 to $1.81 per Mcfe, from $1.92, and our fourth quarter cost actually declined by about $0.13 versus the third quarter.

Now I’ll speak to capital. We had about $23 million that we spent over the quarter. Most of this activity was in three of our four current active growth areas, the Barnett, the Chalk, and our non-op activity in the mid-continent. In the Barnett, where EVEP holds a 31% interest, we had two rigs active all year, and drilled about 40 wells in 2011, not including some of the wells that were being drilled in the new acquisitions when we were closing.

We brought on 12 wells during the quarter, eight in October and another four in December. We have 4 more that were recently fracked and came online in February. Our drilling and completion guys continue to do a good job with keeping costs as expected, averaging about $2.2 million to drill and complete each well. And in the quarter, we were averaging about 10 days from spud to release, which is our best performance yet.

The well-side fees are still ranging from about $1.7 to $2.7 million a day, but on average around our targeted $2 million a day. We’d like to see a bit better IP, but appear to be experiencing slightly flatter decline rates on these wells. We’re already applying some of our learnings from all the drilling in the Barnett to our new areas.

Now I’ll move to the Chalk, where EVEP holds about a 13.5% interest. We drilled our targeted 18 wells, which is only about three net to EVEP during ’11, and we brought those three wells in October, and another two wells were brought online around the first of the year. We’re waiting on two more wells to be brought online.

Results across all 18 wells were pretty much as expected from a production perspective, and our guys kept costs around AFE levels. Just for your example, on average these are about 6.5 million a day wells and they average about 4-5 million equivalent per well, so pretty strong wells. You get a good component of that [oil and the other windows] of that.

The Chalk continues to be a great net cash flow provider for EVEP, and it’s been a wonderful acquisition for EVEP and all the EnerVest partnerships. Our mid-continent area continues to benefit mostly from our non-op activity. We participate in a large number of wells, somewhere around 170-200, with a very small interest in formations such as the [Takwa] and Cleveland granite wash and other formations.

Chesapeake, Sanguine, Chevron, and others are reasonably active in these areas, and we expect drilling to continue in the liquidy areas into 2012. And just a couple of examples in the granite wash, one of our most recent Sanguine wells, came on at 300 barrels a day and 2 million a day, and it’s producing from granite wash formation.

Again, this is the first horizontal test in an area called the Hog Shooter. We also had two other wells drilled by Chevron, the Ledbetter 4021H and 5021H, and Chevron is reporting that they made about a combined 1800 barrels a day and about 2.3 million a day. We have about a 24% net interest in those wells, so we’re really excited about some of that. Again, our information is a bit delayed on those, but it’s nice when we get that in.

If we go to Appalachia, our Appalachia conventional assets have been steady this past quarter. We’ve been a bit slower in the Knox, but as I said last quarter, we did pick up some late in the year. We’ve also been fortunate with some small [clinton] oil drilling, which helps keep things rolling and keeps our oil production reasonably flat.

In the Marcellus in West Virginia, both PetroEdge wells are online and they’re netting about 1 million a day each to our 7% net revenue interest. These are really strong wells. We expect another two wells to be drilled this year, and again, we’re getting carried on those.

So if I look now to acquisitions, if we include subsequent closing in early February, EVEP closed on $498 million of acquisitions in 2011. About $391 million of that is in the Barnett, the remainder for bolt-on acquisitions in existing operating areas, including the Southwest Oklahoma and conventional Ohio. We also sold about $9.8 million of noncore properties.

This level of acquisitions was surprisingly close to our stated goal of approximately $500 million, and our total acquisition costs were about $1.21. A majority of these assets were closed in the fourth quarter, and we have spent the past month integrating these assets. Operationally, we’re off and running.

From an accounting perspective, we’re still in a normal transition period with the sellers, so it will take a month or two before all our detailed information on production and expenses is being managed in house. But so far we appear to be in good shape.

So now let me turn to the Utica. Our Utica acreage position is about 150,000 net working interest acres. We also have the equivalent of a 7.5% override at over 230 net acres. On a growth acreage basis, this translates to about a 2% average override on 880,000 gross acres.

As has been disclosed, we at EnerVest are participants with Chesapeake and Total in a joint venture across several counties in the liquids-rich area of the Utica. The overall deal was $15,000 per acre, for a 25% interest in 619,000 acres. The consideration for the deal was 30% cash and a 70% carry, which we expect to be used over a 3-5 year period. More likely 3 or maybe even less.

EnerVest contributed a total of 77,000 acres into the deal, and EVEP was about 4,000 of that total. EVEP is also participating with a 9% interest in the gathering and a 6% interest in processing and fractionation for this area. We will provide more information on this opportunity as it evolves over the next few months.

The activity continues to increase in the Utica. Our last count had over 120 wells permitted, and Chesapeake alone is [unintelligible] 42. Seven are on production and 35 are waiting on completion. EnerVest entities have participated in 27 of these wells, with now 5 turns in line.

As we understand it, there are several other operators who are also active and moving in to test the potential oil window. EnerVest will participate in about 25-50 wells in the JV this year that’s still being planned out by Chesapeake, Total, and us. As a matter of fact, our guys are in a meeting over the last two days.

We will also participate in a few wells with other operators in the oil window. EnerVest is also partners in the two recent completions, the Burgett and the Shaw, in Carroll County, which were referenced to produce at peak rates of greater than 700 barrels and 3 million cubic feet a day.

We’re pleased with these flow rates, and particularly the condensate yields over the last month, which were around 150 barrels per million. In fact, looking at some economics based on what is a relatively short 1-month period, the economics of the Burgett suggest strong rates of return, very similar to what is being realized by many operators in some of the other liquids-rich shales.

We recently spudded our first EnerVest operated well, the Frank 2H well in Stark County. EnerVest plans on drilling 3-5 wells on our operated production this year, mostly in areas such as the eastern edge of the oil window and other place where it’s not being delineated thoroughly. Generally, EVEP will have a 20-40% interest in these wells.

As we have mentioned several times before, we are currently putting data together to pursue some form of monetization of some or all of our acreage position this year. We plan to formally start the process in the second quarter. We’re obviously visiting with many current and potential Utica participants already.

We will consider joint ventures, swaps, and/or outright sales. We hope to finalize this process sometime later in the year. Ron Gajdica, our head of A&D, who has some good experience in doing joint ventures along with Phil Delozier, our head of business development for EnerVest, are playing key roles in coordinating this process. And as a matter of fact, that’s really one of Ron’s full time jobs right now.

So now if I look briefly at the overall budget, or overall guidance that Mike has spoken to, just to reiterate, we continue to believe that the MLP’s overall goal over time is moderately grow production organically, while leaving the dramatic growth to come from acquisitions. We require 20% return on any capital project at current prices.

That being said, our 2011 capital program is expected to range somewhere between $140 million and $180 million, which again doubles, or almost doubles, last year’s spending levels and will provide some growth in production as the year progresses.

This increase is mostly attributable to our larger Barnett position, particularly in the liquids or combo areas. Our mid-continent granite wash and Cleveland activity, ongoing Knox activity, and increased Utica activity, which will include our first EnerVest-operated wells, kind of finish out our capital program.

So if we assume the midpoint of around $160 million, about 80% is for drilling. About 40% of that will go into the Barnett, with about 94 growth wells, and we’ll have about 3-4 rigs running and can ramp up as it makes sense, although we’re not planning on that at this point.

About 20% of our capital will go into the mid-continent for mostly non-op granite wash Cleveland, etc. About 10% in the Knox, about 10% for Utica, including both our participation interest Chesapeake Total joint venture and EVEP’s share of 3-5 Utica operated wells. Again, as a reminder, on the Chesapeake Total acreage, it’s small for EVEP and we do have a carry.

So 2012 will be a very interesting year for EVEP as we move forward. We’ll be continuing our efforts to modestly grow production in areas where we’re making a return on capital while keeping costs down and continuing to create value in the Utica. While we focus on these areas, we’ll also continue to look for good acquisitions, particularly PDP-oriented deals, and we’ll likely be active in that market as things evolve later in the year.

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

John Walker

Okay, thank you Mark. We’re ready for questions.

Question-and-Answer Session


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 Kevin Smith with Raymond James. Please go ahead.

Kevin Smith – Raymond James

First, if I’m going through your working interest acres, did you guys reduce any of that? I was thinking you had 159,000 and the 4,000 new Chesapeake, but now I think you’re at 150,000. Where am I off?

Mark Houser

The approximately 150,000 is about where we are right now. Again, we did have a sale. Also, we’ve had a group studying these lease records for about 15 months now, and have really honed in on what our actual numbers are. And there’s some of the acreage where, particularly on the fringe areas, some of the acreage may have not had deep rights or other things. And just as we’ve fine-tuned in on it, through a bunch of due diligence, these are numbers that have been evolving, and that’s a good estimate right now with a whole lot of work done.

John Walker

Kevin, I think it will also be dynamic, because we at times create units, we’re buying acreage. So it’s going to stay around 150,000, but it will go up and down some.

Kevin Smith – Raymond James

The other question is if you drill at least 3-5 wells, are they all going to be Stark County wells, the EnerVest, EVEP-operated wells? Have you already laid out counties?

John Walker

Yes, and we have permits, but the first well is in Stark County. The next two that are scheduled are in Carroll County.

Mark Houser

Yeah, and that very well may move around a bit. We’re looking at several different counties right now, as I mentioned, depending on kind of what’s been tested up. We’ve got some in trouble we’re looking at. We’ve got some stuff to do down in Guernsey. A few different areas. Again, we’re trying to go in kind of where it’s not delineated by the other operators right now. And those will evolve.

Kevin Smith – Raymond James

Is there anybody drilling in the oil window? Are you guys participating in the oil window wells I guess is a better question?

Mark Houser

Actually there are several operators as we understand it, in some of the wells we’ll participate in. We understand Devon is drilling some or planning to. Also, Anadarko has got some plans to drill some. We know Chesapeake as well is doing some. Again, we’re not participating in every Chesapeake well. There’s some that we’re not involved in. But yeah, there are others actually drilling quite a bit, as we understand it, now, in the oil window.

Kevin Smith – Raymond James

And then lastly, and I’ll jump off. Can you tell me how much production from your Barnett transaction closed in February versus what closed in December. Just want to try and get a feel for how much that’s going to incrementally impact Q1 numbers.

Mark Houser

Mike is saying about 10% or 15%, Kevin. That might be something we can follow up with you on if anybody has questions on that.

Michael Mercer

I think it was about $29 million that closed. I know it should be less than $15 million, probably closer to $10 million, but don’t have that exact number, Kevin.


Thank you. And our next question is from the line of Ethan Bellamy with Robert W. Baird. Please go ahead.

Ethan Bellamy – Robert W. Baird

Is it safe to say that there’s really no change to the acquisition plan or anything that would prevent you from doing other deals while the Utica disposition gets worked out?

John Walker

Let me make a first shot at that. I think that obviously we’re interested in trying to maximize what we get per share out of the Utica. But at the same time, I don’t want to say that we’re not going to do other acquisitions. I’d just say that the acquisitions that we do up until the time that we monetize the Utica will have to be compelling.

Mark Houser

And just to add to that, as I mentioned, Ron Gajdica’s full time job right now - normally it’s A&D and right now his big full time job is this Utica monetization.

Ethan Bellamy – Robert W. Baird

So I assume Ron’s learning French then. [laughter]

Mark Houser

Ron speaks multiple languages.

Ethan Bellamy – Robert W. Baird

Maybe some Mandarin or something. With respect to the assets that have been maturing and you’ve been developing at the EnerVest level, and I guess the same thing for EnCap, is there an inventory of stuff there that we can think of in terms of drop downs that might be more visible than we were, say, a quarter or two quarters ago?

John Walker

I’d say that right now, Ethan, the problem is that gas prices are so low that our institutions and the EnCap institutions don’t want to sell gas properties or properties that too high a component of ethane in the NGL stream. And so it’s not a high likelihood, at least in this market, and I’m not overly optimistic about gas prices as we move toward September either.

Ethan Bellamy – Robert W. Baird

And does that then imply, John, that long term you’re looking for a bounce back in gas, or are you fairly bearish on gas going into 2013?

John Walker

I think that the best thing that could happen to the industry is what’s happening. The mild winter has created a very traumatic event for our whole industry, and I think it’s going to knock some sense into some of our E&P counterparts who are already seeing that with the gas rate count down over 200 [rigs].

But I think we’ve needed this rather than dying a thousand deaths, and so I think it will help bring supply and demand partially into line. But we still need more demand growth in natural gas, and so I don’t want to outright say that all of a sudden everything’s going to be peachy keen, but it’s not going to be, because the thing that’s restricting a lot of gas supply right now, as you’re aware, gas supply growth has flattened out. But that’s more constrained by the addition of processing plants and lines than it is by the ability to hook up some of these wells.

Ethan Bellamy – Robert W. Baird

Okay, and then one last question. You know, from my perspective, probably the most nebulous thing to get a handle on in terms of value is the overriding royalty interest. Is your bias to include that in some type of a monetization or keep it, because it’s a no capex MLP suitable asset.

Michael Mercer

It’s an MLP suitable asset.

Mark Houser

That would be something we’d prefer to keep.

Michael Mercer

We’d prefer to keep it.

John Walker

Yes, it’s going to have a lot of value to it.


Thank you. And our next question is from the line of [Tony Langham with Corey Partnerships]. Please go ahead.

[Tony Langham - Corey Partnerships]

John, at the Wells Fargo meeting in December, you made the comment regarding the Utica that $15,000 you viewed as a base price, and you said that it would get much better than that in the oil window and somewhat better than that in the gas window. Is that still your feeling? In the NGL window.

John Walker

I do think that a certain base has been realized with Total and they made that decision without information on the Shaw and the Burgett, and the completion technique - and Mark can go into it in more detail if you’d like - that we’re using now, where we’re [unintelligible] in these wells 60-90 days, to allow the dissipation of some of the frack fluids that seem to have hindered some of the early wells. It really is helping. And [unintelligible] has really helped the quality of the well. So I think the answer is the NGL window, probably is getting somewhat more valuable, and clearly with oil prices relative to NGL prices, assuming that we can figure out how to properly complete these - and I think we will as an industry - then that’s obviously a lot more valuable.


Thank you. And our next question is from the line of Adam Leight with RBC Capital Markets. Please go ahead.

Adam Leight – RBC Capital

Just real quickly from me, on the capital budget, I guess starting out with maybe an update on your overall decline rate at this point, and what it needs to swing [talk over].

Mark Houser

Right now our decline rate, if you add up all of our proved reserves, our time projected, base decline rate is about 9.6% reserve. Decline rate on PDP, on a 5-year average. And that’s really what we’re kind of looking at. As we drill some of these wells in the Barnett, early on, they’re going to come down reasonably quickly, but again, we’ve got some good organic growth in there and our job is to maintain or slightly grow that through the whole portfolio. But in terms of final, 5-year average right now is about 9%+.

Michael Mercer

And that’s just on PDP, Adam.

Mark Houser

That’s just PDP.

Michael Mercer

That’s just PDP blow down, starting out initially in the very low double digits, coming down and ultimately leveling out at a little under 6%. But that’s probably 6 or 7 years down the road.

Adam Leight – RBC Capital

Of the 20% of the capital budget that’s not assigned for drilling, how much of that’s infrastructure recompletions work over these leases?

Michael Mercer

We have about $10 million or so of seismic, and actually that may actually be reduced some due to some things we’re working on. We have about another $5 million on kind of refracks and acid jobs. And then we have some land costs in there as well of about $5 million. Again, as we mentioned, we do have some, from time to time, acreage that we need to pick up in the Utica just to kind of fill in the honeycomb, so to speak.

Adam Leight – RBC Capital

The maintenance level, how much of that is necessarily to maintain production at this point?

Mark Houser

Well, we’ve typically said about 25% of EBITDA, which is about $1.25 per m equivalent generally is our maintenance capital. We review that every quarter with the board, and of course with costs coming down on the gas side, and us being a gas company, it’s conceivable that could come down, but we just have to manage that.


Thank you. [Operator instructions.] And there are no further questions in the queue at this time. I would now like to turn the call back over to management for closing remarks.

John Walker

Well, we’d like to thank all of you for joining us this afternoon, and look forward to visiting with you for our first quarter report. Thank you very much.

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