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Encore Acquisition Company (NASDAQ:EAC)

Q1 2008 Earnings Call

May 8, 2008 12:00 pm ET

Executives

Jon S. Brumley - President, Chief Executive Officer and Director

Robert C. Reeves - Chief Financial Officer, Senior Vice President and Treasurer

L. Ben Nivens - Chief Operating Officer and Senior Vice President

John W. Arms - Senior Vice President, Acquisitions

I. Jon Brumley - Chairman of the Board

N. Kevin Treadway - Senior Vice President, Land

Analysts

Brian Singer - Goldman, Sachs & Co.

Joseph Allman – JP Morgan

Analyst John King

Stephen F. Berman - Pritchard Capital Partners

Noel A. Parks - Ladenburg Thalmann

Analyst [Scott Loomis]

Analyst [Martin Perlman]

Analyst [Sean Grant]

Analyst [Monroe Hemm]

Pavel Molchanov - Raymond James & Associates

Analyst [Mike Tapp]

Analyst [Mitchell Wardschmidt]

Analyst [Matthew Kogan]

Operator

Welcome to the Encore Acquisition Company and Encore Energy Partners L.P. conference call. (Operator Instructions)

This presentation includes forward-looking statements. Forward-looking statements give Encore’s current expectations or forecasts of future events based on assumptions and estimations that management believes are reasonable given currently available information. However the assumptions by management and the future performance of Encore are both subject to wide range of business risks and uncertainties and there is no assurance that these statements or projections will be met.

Actual results could differ materially from those presented in the forward-looking statements. Encore undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Encore’s filings with the Securities and Exchange Commission.

I would now like to turn the call over to our host, Jonny Brumley.

Jon S. Brumley

We’re very excited about the first quarter. In the room with me is Bob Reeves, our CFO; Ben Nivens, our COO; John Arms, Senior Vice President of Acquisitions; Jon Brumley, Chairman; and Kevin Treadway, Senior Vice President of Land.

The first quarter of 08 was a great quarter, high oil prices and more production. We beat production guidance by 700 barrels of oil equivalent per day, generated $189 million of EBITDAX and the LOE beat estimates about $0.14. Another bright spot in the quarter is our oil differential. It was just 9% versus of guidance of 14%. The company’s firing and oil filters, we’re pleased with this quarter and think the second quarter will be even better. We’re also excited about the new distribution policy at Encore Energy Partners and we’ll be going over that later in the call but for the first part of the call we’ll be focusing on Encore Acquisition Company and then we’ll discuss Encore Energy Partners.

You can really see the quality of our properties when you look at our EBITDAX per BOE margin. We like EBITDAX to be about 60% of revenue and because we’ve done a good job with our costs and the differentials have tightened we’re about 70% of revenue. I’m really proud of our marketing group and our operations group and the good work they’re doing and we’re bringing a lot to the bottom line. And that’s the benefit of being oily. Oil properties are a much higher margin than gas properties. $120 oil is about the same as $20 per MCF gas on a 6:1 ratio. Gas is great but oil is a whole lot better. Now let’s focus on the operation and we’ll start with the Williston Basin and our Bakken program.

Our Bakken program is getting bigger. We have moved north from our established core area at Murphy Creek into Bear Creek and we’re seeing similar results. We’re more excited than ever about our acreage and are planning to add a third rig in the Bakken sooner than what we discussed in March of 2008. Our original plan was to move the two rigs in June which will happen and under the original plan to move to the third rig in January of 09 but because of the success we’re seeing in the Bakken program and the success that other operators are having in and around our acreage we’ll be adding the third rig in August of 2008 and then we’ll add a fourth rig in January of 09.

We’re confident that this accelerated pace will add the most value to Encore and the wells at Bear Creek are looking good. The average seven day IP is 375 barrels a day but they’re declining at a shallower rate than our core Murphy Creek area so we’re excited about this and we feel very, very comfortable with the 250,000 barrel reserve estimate at Bear Creek.

Now we’ll begin discussing the Charlson area in the Bakken play. Charlson is an important area because we’ll be offsetting the best well drilled in the Bakken play today. It was drilled by a private company and we own a 3% interest in the well. This well has been relatively flat and has produced around 350,000 barrels in the first year of production so obviously we’re excited about the Charlson program and offsetting this big well. Our leasing program has been going well. We’re up to 180,000 net acres that is up from 155,000 in March. Our acreage looks good; it’s getting better as we see success in all of our programs and see success in the offset operators. Since the second rig has a lower day rate than the first rig we’ll be enhancing our economics in the Bakken. We keep figuring out ways to bring more and more to the bottom line.

Now we’ll transition to the Madison play also in the Williston Basin and it’s looking good too. We previously announced a well we drilled in the TR unit. It came on at 700 barrels of oil per day and we followed that up with three additional wells. We’ve completed one of the three and it’s producing 265 barrels per day and that’s a little better than the AFE estimate so we feel good about this and ready to get the other two wells on. The Williston Basin is the most undrilled large producing basin in the lower 48. Since we’re the largest oil producer in Montana and the fourth largest in North Dakota we have a great position. We have a nice balance in the Williston Basin between blocking and tackling exploitation with the Madison and then the huge resource potential that the Bakken offers. We’re now up to 280 potential locations in the Bakken and over 80 in the Madison.

Now we’ll transition to West Texas and discuss our JV with ExxonMobil and the JV is going well. We’ve completed the commitment phase in the Parks, Pegasus, Wilshire and the Brown Bassett fields. Only two re-entries were made in the Delaware Basin. We have drilled all the complicated dual horizontal wells and now are focused on the lower risk single lateral wells. Efficiencies in the JV are improving dramatically well by well. The last horizontal well at Wilshire was drilled in a record of 43 days versus a plan of 52 so we look forward to taking these efficiencies to Pegasus where the prize is much larger and there’s much more to do at Pegasus.

We’ll begin our post-commitment phase at Pegasus next month with the spudding of three wells. We will have a total of six drilling rigs running on the West Texas JV and are enjoying good growth. The JV’s current net production is 12.2 million cubic feet a day and that’s up from 4.3 million at the end of the first quarter 07. That’s a lot of growth and it’s only getting better as we transition into the post-commitment phase. That is one of the themes that I want investors to take notice of is our programs are good and they’re getting better.

Another exciting play in West Texas is our Wolfcamp/Penn Detrital at the Sandhills Field in Crane County. In the third quarter of 05 Encore drilled and completed a well in the Penn Detrital formation. The well came on good at 170 barrels a day but in the fourth quarter 07 we re-completed up-hauling the Wolfcamp and the well tested at 425 barrels a day. We’re currently drilling three offset wells to better define the play but if this is successful it could be pretty big. It could be one right for three and a half years. So we’re excited about this in the Sandhills area. This could lead to a lot of up side potential on our 17,000 acres which is mainly held by production and we have 100% working interest in it. New Mexico is also looking good. At the beginning of the year production was 6.7 million cubic feet per day. Now it’s 9.3 and we’ll maintain one rig program through 208.

Now I want to talk to you about some new areas in play that’s been working on at Encore. We’ve been working on a play called the Tuscaloosa Marine Shale in Southern Mississippi and the Florida parishes in Louisiana. Because we drilled and permitted two wells in the TMS attention has been drawn to the play and we thought it was appropriate to mention the play in the press release and discus it on the call. We’ve leased 208,000 net acres in the TMS and have drilled two wells. We became interested in this play because of three blowouts and numerous high pressure kicks that have occurred while drilling through the Tuscaloosa Marine Shale on the way down to the Tuscaloosa sand. The Marine Shale is a source rock for the Tuscaloosa sand. So we started looking closer and we discovered a silt stone in the shale that we believe would have enough integrity to drill a horizontal well into it.

It looks like we were correct. We’ve cored the wells and see vertical fractures in the core and we know that we can drill horizontals in this. This is an early phase resource play. The first well is a horizontal well that we were able to drill out about 1,650 feet with a horizontal lateral. We were originally hoping to get out about 4,500 feet but because of drilling problems we could only get out 1,650. That well is on pump and it’s making between 150 and 200 barrels a day. The second well we drilled we were able to get out 3,100 feet. We have just recently fracked that well and are waiting on production results but this is a huge resource and we’re excited about making oil out of our first completion. What we know about the TMS now is we can drill horizontal lateral, we can produce oil and we think as we link the laterals we ought to see the wells improve. We have a lot of work in front of us. We need to drop the drilling costs, extend the laterals and optimize our stimulation techniques to make the wells better and better but when we figure this out we’ll have a lot of running room. We know the oil is there, we just need to figure out the best way to get it out.

Now we’ll be talking about our Haynesville position in [Arkmatex]. We have 10,000 net acres of Haynesville potential in and around Elm Grove and the Greenwood Wascom fields and there is a large well close by to the Greenwood Wascom field. This play will be getting bigger as the operators begin exploiting the Haynesville and we’re also right in the middle of the new Cotton Valley horizontal play. [Petra Hockencamp Terra] operates most of that acreage but they’re good operators and have been generating great results in the horizontal Cotton Valley.

Another play we have is the Cleveland horizontal play in Western Oklahoma. We have been involved in the Cleveland since 2005 and it’s getting large enough to warrant mention on the call. We have participated in 30 wells with working interest ranging from 15% to 37% and have grown our acreage position from 8,000 to 20,000 net acres. Wells come on at 1,000 MCF a day and 250 barrels of oil a day for a drill and complete cost of $2.8 million. That’s good economics in those wells. The play is economic and we’re glad to see it growing to a bigger and bigger piece of Encore and we expect to have about three wells per 640 acre section in this play.

I think it’s clear that our team is performing, our inventory is growing and the budget is adding significant value. Since 2006 we have been working extremely hard to grow the inventory and now you’re seeing that inventory start to evolve. The plays that we have started since 2006 have been the West Texas JV, the North Dakota Bakken, the Haynesville and Horizontal Cotton Valley in North Louisiana and East Texas, the Cleveland Sand play in Oklahoma, the West Texas Barnett and the 208,000 acres we’ve leased in the Tuscaloosa Marine Shale. They’re in various stages but they are all exciting.

I’ll finish the EAC portion of the call with the important guidance numbers. Product guidance for the second quarter is expected to be in the range of 37,500 on the low end to 38,900 on the high end. LOE is expected to be $11.75 per barrel and the differentials for oil are expected to be around 9%.

Now we’re going to talk about Encore Energy Partners and we’ll start with the new distribution method and I want to stress that this is an ongoing change to the policy not a special one time distribution. Previously the partnership had been retaining more cash flow than we think is appropriate for this type of investment so we created a new distribution methodology. We believe this new method is conservative but will still allow us to distribute more money to the unit holders. The new distribution method at Encore Energy Partners is the following; the MQD will be $1.73. We’ll have a minimum coverage ratio of 1.1 times then we’ll distribute about 50% of the excess cash flow over the $1.73 and 1.1 times coverage to the unit holders. And we’ll pay down debt with the other 50%. For the first quarter this rate the distribution from $43.25 per unit to $57.05 per unit. Because the partnership retains 50% of the cash flow over the $1.73 and the 1.1 times coverage ratio the actual coverage ratio is 1.4 times. This will introduce a variable component to our distribution but will allow the unit holders to get more distributed back to them during this time of high commodity prices and still allow us to run the partnership conservatively.

When we formed the MLP we started with high quality, long life properties that have very low maintenance cap ex requirements. Because the properties require such a small amount of capital as compared to their EBITDAs or remain flat we decided we did not need to keep all this cash flow. We felt that the unit holders would rather have the cash flow than us keeping it. That’s why the invested on an upstream MLP in the first place. We could not do this if the properties weren’t so good. Our capital budget for the MLP is only $14 million and EBITDAX is estimated to be $102 million at $85 dollar oil. But we think that this new distribution method makes a lot of sense and combines the positive attributes of a high quality US royalty trust with the good management and hedging strategy of an upstream MLP.

ENP offers the investor of both. As we grow the partnership we’ll continue to increase the MQD from $1.73 but we’ll also distribute to the unit holders about half of the excess distributable cash flow. When I say that we’ll distribute about half the cash flow what I mean is if we foresee a heavy quarter coming in the future it might be a little less than half and if we see a light capital quarter come in the future it might be a little more than half. But all in all it will average out about 50%. We built this partnership to succeed; the new distribution policy highlights the innovative things you can do with a great set of properties, a savvy hedging strategy and a clean balance sheet.

Another exciting deal we’ve done is purchased our first set of properties using units. This is a relatively small acquisition of $5.8 million but it’s a focus for the partnership. We see this as a great way for private companies to sell us properties, become liquid and enable the family members who want to stay linked to the oil and gas business to hold the units and those who want to become liquid can gain liquidity.

Now we’ll talk about the operation for the properties in the MLP. The production for the MLP was 6,309 barrels of oil equivalent per day and EBITDAX was $31.8 million. Elk Basin has also seen an increase in its wellhead oil price relative to NYMEX. We were budgeting a differential of 19% for 2008. That current differential is only 11% so Elk Basin is really performing well. For the second quarter we’re expecting production to be between 6,000 and 6,600 barrels of oils per day and the capital to be $3 million and right around $14 million for the year. As for the second quarter if prices are high cash distributions will be a little higher, if they remain the cash distribution ought to be pretty close to what it was for the first quarter and if they drop it will be a little bit less.

Now I’ll open the call up for questions. Oh, one more thing before I do that, we do have a presentation on our website for the TMS. Just go to our website and it’s under Presentations.

Question-And-Answer Session

Operator

(Operator Instructions) Your first question comes from Brian Singer - Goldman, Sachs & Co.

Brian Singer - Goldman, Sachs & Co.

Couple questions, first on the Bakken. At Bear Creek I think you highlighted that while you had some lower IPs the EURs looked like they were trending higher which I guess implies some lower decline rate. Can you talk a little bit more about that and maybe be specific as to what you think the EURs are coming in at from these initial wells?

Jon S. Brumley

We feel real good about the 250,000 barrel base model but it could be a little bit better than that. There is a little bit more gas in that area and so that’s just helping to drive the oil in maintaining the production rates a little bit better than Murphy Creek.

Brian Singer - Goldman, Sachs & Co.

How are you looking at declines and decline rates off of the IP rate to get to that? Is there a dramatic difference that you’re seeing?

L. Ben Nivens

It’s not a dramatic difference and these wells haven’t been owned for a long time but we are seeing a shallower decline on these initially and we think that’s going to hang in there. We were talking at Murphy Creek 440 for about 200 to 250 here we think 370 is about the same.

Brian Singer - Goldman, Sachs & Co.

Switching to Charlson, what was the data point that caused you to accelerate drilling now? It seems like it’s more than just high oil prices.

Jon S. Brumley

It’s this Charlson opportunity. We need to get on this. That’s a huge well and so we’re going to be drilling that and following our first Charlson well up with four more. So we’re just going to knock out five wells in the Charlson area.

Brian Singer - Goldman, Sachs & Co.

Was there something specifically though that told you to set the time to do it now versus, why hadn’t you thought about accelerating earlier?

Jon S. Brumley

I think it’s because of the success that we’re seeing. We started at Murphy Creek and that was 250,000 barrels. Then we moved up to Bear Creek and we’re seeing even a little bit better results there. So we have a lot of confidence in our geologic models at the Bakken now and this Charlson area has a huge well next to it and it’s just screaming to be offset. We’re not going to just offset it with one; we’re going to have a five well program up there.

L. Ben Nivens

Some of it was we were continuing to lease in Charlson and there is some permitting that has to be done. So it really wasn’t a delay, we were working hard to get up there.

Brian Singer - Goldman, Sachs & Co.

Last thing in the Tuscaloosa Marine Shale, can you talk about the cost of the drilling and completion costs for the first two wells and what you think a realistic cost could be if you were to more things more into development?

Jon S. Brumley

The appraisal wells are a little more than $10 million. I think that we can move that down to $6 million.

Brian Singer - Goldman, Sachs & Co.

And that would be for a 3,100 foot or would it be that a 4,500 foot well?

Jon S. Brumley

4,500 feet.

Brian Singer - Goldman, Sachs & Co.

Thoughts on EURs or still too early?

Jon S. Brumley

It’s still too early. We’re just excited that we can place a horizontal lateral where we want to place a horizontal lateral. The zone is showing integrity to maintain that lateral and drill that lateral and then we’re producing oil out of a less than optimal well. 1,650 feet was a lot of good things because we did get the well drilled but we were very disappointed in that length.

Operator

Your next question comes from Joe Allman.

Joseph Allman – JP Morgan

Actually this is Joe Allman. On that Tuscaloosa Marine Shale, are there other targets besides that shale in the area?

Jon S. Brumley

There is some shallower targets but this is really what we’re going after.

Joseph Allman – JP Morgan

Getting it down from say $10 million to $6 million what do you think the big drivers are there?

L. Ben Nivens

The big drivers are going to be primarily on the drilling costs and maybe a little bit on the completion costs but these are complicated wells, they’re deep and they’re long laterals and this is a brand new area and as we learn the area we believe we can drop the drilling costs down. The first wells were done technically to make sure that we got the well down and drilled successful laterals and we’ll work on the exploitation of that as we move forward.

Joseph Allman – JP Morgan

Can you just talk about in general the cost environment you’re seeing? Are you seeing pressure on service costs here?

L. Ben Nivens

We are seeing a little bit of pressure on service costs. We had seen a flattening in the first part of the year but with prices going up as they had in the last couple of months we are beginning to see some pressure on costs.

Jon S. Brumley

Another thing I want to bring up on the call, this doesn’t relate to your question but that Bakken refrack program is pretty exciting. We increased that well from 60 to 130 barrels a day for only $500,000. We’re going to be trying four more of those and so that could really increase the reserves and the economics on this Bakken play are these refracks and we’re real excited about this and we’re jumping on that pretty quick after seeing success. We’ve lined up four of them.

Joseph Allman – JP Morgan

How many opportunities might you have to do the refracks?

L. Ben Nivens

You have opportunities in every well bore and maybe multiple opportunities as you look forward. We’re not sure that one refrack is all that you can do in a single well.

Jon S. Brumley

This could be a big deal for just the whole play.

Operator

Your next question comes from John King.

Analyst John King

I have a question in concern with the MLP with these higher commodity prices now that you have a new formula approach to distributions. Do you think that will affect your drop downs from EAC to ENP? Would you be less inclined as distributions are high to make drop downs?

Jon S. Brumley

I don’t think so. I think we’ll making drop downs. We see that as a way to finance EAC and that will be beneficial to ENP because they will get an accretive drop down. I think that you’re seeing more and more opportunity at EAC and as we are working on our 2009 budget, if that budget is expanded one way to fund that expansion is through a drop down into ENP. So actually I see it as beneficial to both. The healthier EAC’s drilling inventory is the better off ENP is because that’s one of our main financing routes is to drop properties into it.

Analyst John King

Which is also great for EAC as well to have the healthy drilling inventory.

Jon S. Brumley

Yes.

Analyst John King

On that note, would you be able to give a little more detail in terms of how much you have that’s potentially drop downable into the MLP at this point?

Jon S. Brumley

Basically 65% of the company’s water floods so that would all fit and then we have some long life gas properties. You’re getting into 65% to 75%, 80%.

Analyst John King

A last question for me is as we calculate the distributable cash flows, the 50% increase over the 1.1 coverage; we need to include the effect of the MIUs, the management incentive units, when calculating the 50% or is that outside the 50%?

Jon S. Brumley

It includes it.

Operator

Your next question comes from Steve Berman.

Stephen F. Berman - Pritchard Capital Partners

Question on the JV, did you drill any non-commitment wells in the quarter?

L. Ben Nivens

Yes, we did. The two Pegasus wells that we drilled and are completing were non-commitment wells and we drilled one of the deep Brown Bassett wells I know was non-commitment well. Most of the wells we’re drilling now are non-commitment because as Jonny mentioned most of the wells outside of the Delaware Basin have already completed the commitment phase. What we’re drilling now is mostly non-commitment wells.

Jon S. Brumley

The Delaware Basin is the only area where we haven’t drilled the commitment wells and we have two re-entries that we have to drill in that area.

Stephen F. Berman - Pritchard Capital Partners

In the Haynesville is this acreage you’ve had for a while and I’m also wondering if this is, there is some very big prices getting paid for acreage over there, I’m just wondering if you see this as a core area going forward or possibly something you could take advantage of the big prices getting paid and maybe a source of funds for you? What do you see for yourself going forward there?

Jon S. Brumley

It’s pretty early in the play. We’re really not sure what we’re going to do with it but we are excited about it. We’re leasing this for Cotton Valley and Cotton Valley horizontals so we’re very excited to see this happening. But the Cotton Valley has been a core area for Encore and this is definitely an enhancement to our core area.

Stephen F. Berman - Pritchard Capital Partners

Balance sheet question, do you have a breakdown of the debt just for Encore without ENP?

Robert C. Reeves

We had $415 million on the credit facility and then the $600 million of bonds. There’s $165 million on MLP.

Stephen F. Berman - Pritchard Capital Partners

Sorry, Bob, can you repeat that?

Robert C. Reeves

$165 million is what’s on the MLP; $165 million on the credit facility and the rest is on EAC.

Operator

Your next question comes from Noel Parks.

Noel A. Parks - Ladenburg Thalmann

Just a few things, with the Tuscaloosa Shale, have you talked about the depth that you’re drilling at there?

Jon S. Brumley

The Tuscaloosa Shale is between 10,500 feet and 13,500 feet. Most of our drilling is going to be between 10,500 and 12,000.

Noel A. Parks - Ladenburg Thalmann

Do you have a sense of how prevalent this silt stone member you talked about is across your acreage? Is it something that’s everywhere? Or too soon to say?

Jon S. Brumley

It’s everywhere in some instances it becomes very thin. So we leased where we thought it was thick.

Noel A. Parks - Ladenburg Thalmann

I’m assuming there were legacy vertical penetrations that gave you some idea of that?

L. Ben Nivens

The Tuscaloosa Sands were a target out here for a long time and they set below the Tuscaloosa Marine Shale so you had quite a few penetrations through the Tuscaloosa Marine Shale.

Noel A. Parks - Ladenburg Thalmann

It seems that there’s a new project on the slate, is the work on it over the next few months or quarters, is it going to be very manpower intensive with your technical staff or is it the sort of thing just a handful of people will probably work on?

Jon S. Brumley

It will be manpower intensive because it’s such a big and meaningful opportunity and we want to do it right. But we have enough manpower to maintain the drilling program that we are doing and also do a good job on this.

Noel A. Parks - Ladenburg Thalmann

I also was curious with the Sandhills field you talked about, you said I think you have 17,000 acres there and you have the offsets you’re going to be drilling right now [inaudible] question do you have a sense of ultimately what the opportunity could be across that?

Jon S. Brumley

Are you talking about the Penn Detrital opportunity or the Barnett opportunity?

Noel A. Parks - Ladenburg Thalmann

Penn Detrital, but could we hear about both?

L. Ben Nivens

We think that the Penn Detrital is perspective under a fair amount of that but it’s not going to be a blanket type play like the Barnett would be. It would be a smaller area than that but the Barnett if it is perspective might be perspective over the entire acreage.

Noel A. Parks - Ladenburg Thalmann

What depth do you have at the Barnett and that part of the Delaware Basin?

L. Ben Nivens

About 8,000 feet, 8,000 to 9,000 feet.

Noel A. Parks - Ladenburg Thalmann

Barely shallow I guess as the play goes, right?

L. Ben Nivens

Yes, and it could possibly be oil under the Sandhills area.

Noel A. Parks - Ladenburg Thalmann

Just a couple more, you know one thing talking about the MLP I thought from the drop down, this is maybe a question for Bob, I thought with the drop down there was going to be some sort of item on the income statement for the first quarter, I remember some sort of valuation charge or different markup in valuation, did I get that wrong or was that something that just consolidated out?

Robert C. Reeves

Are you talking about the costs associated with the drop down like the administrative costs?

Noel A. Parks - Ladenburg Thalmann

I had thought as you shifted the properties from one entity to the other, there were some charge was going to happen.

Robert C. Reeves

Yes, there is. There’s a tax charge that we’re taking on EAC associated with the drop down. A part of the sale is considered a contribution of assets and a part of it considered a sale. So we did take a tax hit on that. We have about a $45 million gain associated with this drop down and you take that times our effective tax rate of about 37.5% so we have taxes associated with it of about $16.5 million but through the credits that we have from high pressure air and alternative minimum credits and just our drilling for the year the true tax impact of that is going to be about $4 million for the year. Not a very big deal.

Noel A. Parks - Ladenburg Thalmann

And that’s going to hit in a future quarter or it already hit?

Robert C. Reeves

We took the charge this quarter and paid the taxes.

Operator

Your next question comes from Scott Loomis.

Analyst Scott Loomis

What’s that number looking like now?

L. Ben Nivens

With the third rig it will probably go up to 38 to 40 wells because we’re giving it about 30+ stay wells and we’re starting in the middle of the second quarter.

Analyst Scott Loomis

Now is the third rig going to have a comparable rate to the second rig?

L. Ben Nivens

We haven’t contracted that rig yet but we think so.

Analyst Scott Loomis

Moving to the West Texas Barnett, what incremental costs do you guys see in deepening to the Barnett?

L. Ben Nivens

These deepenings that we talked about are going to be relatively cheap because the Barnett is just the next zone underneath of the zone that we’re going after. So the deepening and testing will be relatively cheap for these three tests.

Analyst Scott Loomis

What’s the timing on this test?

L. Ben Nivens

We are drilling the first well right now.

Analyst Scott Loomis

With all the increased activity are you guys planning on remaining within your previously stated budget?

Jon S. Brumley

It will be a little bit over because we’re adding a rig in the Bakken area so if it was 445, those rigs are about $3 million a month, so it would be $15 million increases from that rig.

Operator

Your next question comes from Martin Perlman.

Analyst Martin Perlman

Going back to the partnership you mentioned $14 million in capital expenditures this year, is that meant to maintain production at the current levels or is it looking to create a modest increase?

Jon S. Brumley

It’s meant to maintain. That’s a strategy that we have at Encore is basically maintain our shallow declining properties with the cap ex budget and then grow though acquisition and drop down.

Operator

Your next question comes from Sean Grant.

Analyst Sean Grant

This is actually Adam Rossamer. I noticed that your oil differential on a blended basis at ENP came down and I wanted to know the market dynamics that are affecting that and where you expect it to go?

Jon S. Brumley

There’s just a high demand for crude and this crude is a sour asphaltic crude and they’re not discounting it. All throughout the US sour crude has really outperformed sweet crude over the past six months and so you’re starting to see that in the prices at the field. It’s the same as West Texas sour and a few of the sour units that we have at the Cedar Creek Anticline.

Analyst Sean Grant

Do you expect it to continue to come in?

Jon S. Brumley

What do we have in guidance for the next quarter?

Robert C. Reeves

Right now we’re guiding it to be 13%.

Jon S. Brumley

We expect it to widen out some but still stay relatively tight. I think that we’re at about 20% on the road show so you’re seeing a huge benefit from that.

Operator

Your next question comes from Monroe Hemm.

Analyst Monroe Hemm

Just a follow up on some additional color on this Charlson area, what do you think the private up here is, you drilled this well? When do you think they think the EURs on that particular oil and what interest will you have in the five wells that you’re going to drill in that area?

L. Ben Nivens

We don’t know what the EUR is on that well and our interest up there in the Charlson area varies greatly from well to well. The average is probably a little greater than 50%.

Analyst Monroe Hemm

Any analyses between this and the Parshall field? It seems like there’s certain areas in the block and I know its early days and there’s some sweet spots. Can you make any comparisons between this and the Parshall field?

Jon S. Brumley

It appears like this well is better than the wells in the Parshall field given that it produced; basically it’s produced 430,000 barrels since it has been on. It produced 350 in the first year and that’s without a frack job on it. Looks like a hell of a well.

L. Ben Nivens

It’s definitely, it’s better than the Parshall wells and whether it’s for the same reasons or not that these are very high anomalous areas we don’t know but it’s definitely a very good area.

Analyst Monroe Hemm

You mentioned that you had picked up maybe 25,000 acres in the Bakken; can you be more specific as to where that acreage is that you picked up since the beginning of the year?

Jon S. Brumley

About half of it is to the West of the Madison Anticline where we’ve seen some good activity and good wells drilled over there and then part of it is a little bit North, well it’s East of the Anticline, North of the Parshall field. But a good deal north. I’d say 12 miles or so.

Analyst Monroe Hemm

Are you still trying to add acreage up there?

Jon S. Brumley

Yes, we’re trying to add acreage. I think that we will be increasing; we’re trying to get to 250,000 barrels a day. We started the year at around 150,000, we’re up to 180,000. I mean acres. We started at 150,000 we’re up to 180,000 now so the leasing program is going good, it’s getting more competitive up there but we have a hell of a land group that was able to pick up, basically grow from 48,000 to 180,000 in a year in a hot flame before it got really hot.

Analyst Monroe Hemm

What kind of prices are you having to pay for the acreage and what royalties at this point in time?

Jon S. Brumley

It all depends. We don’t really go over that because it’s so competitive that we don’t want to tip our hand.

Analyst Monroe Hemm

When you mentioned earlier that half of this acreage you picked up was north of the Parshall, is this in this almond area that you show on your map?

Jon S. Brumley

Yes, that area is about 30,000 acres. That area is getting pretty busy, there is three wells being drilled up in around there.

Analyst Monroe Hemm

That’s a big part of what you picked up this year then?

Jon S. Brumley

I don’t know if we picked it all up in 08 but part of it was.

Analyst Monroe Hemm

In the Tuscaloosa Marine Shale, how thick is this horizontal section that you’ve identified? I’m sure it varies over the acreage but the thickest part of it, what would you say the horizontal section is that you can drill in?

Jon S. Brumley

The Tuscaloosa Marine Shale varies between 100 and 150 feet thick. The silk stone that we’re targeting is anywhere between 10 and 50 feet thick across our acreage.

Operator

Your next question comes from Pavel Molchanov.

Pavel Molchanov - Raymond James & Associates

Quick question first on the Tuscaloosa you mentioned you have 85% working interest. Can you tell us who the other 15% is?

Jon S. Brumley

It’s a private company that has, a lot of the acreage we have 100% working interest and some of it we have 75%. It averages out to be 85% and that’s a private company.

Pavel Molchanov - Raymond James & Associates

Is Encore the operator across the board on the 200,000 acres?

Jon S. Brumley

Not across the board but probably 80% of it.

Pavel Molchanov - Raymond James & Associates

Second, and sorry if you mentioned this before, given where commodities are right now, are you looking to boost your cap ex budget up from the initial level of $450 million and then same question with regard to the partnership?

Jon S. Brumley

The partnership cap ex budget is really not going to be boosted. The C Corp EAC’s budget, we’re doing a little bit more work but it’s not just a ton more work and so we’ll be leasing more and the acreage is going for more. That will outspend our land budget and then our drilling budget by adding that rig in the Bakken will increase by another $15 million.

Operator

Your next question comes from Mike Tapp.

Analyst Mike Tapp

The 208,000 acres in the Tuscaloosa Marine Shale, if you mentioned this already I apologize, but is any of that HBP?

Jon S. Brumley

No.

Analyst Mike Tapp

What are the lease terms on that?

Jon S. Brumley

I don’t know like going over lease terms on the conference call. Cheaper than the Barnett Shale.

Analyst Mike Tapp

No, no, no. I meant in terms of five year leases.

Jon S. Brumley

Oh, I’m sorry. We’re getting five year leases.

Analyst Mike Tapp

Going back to the cap ex budget, it seems like the guidance that you gave earlier, you guys are on pace to well exceed the discretionary cash flow guidance that you gave, so would you in addition to looking to expand your drilling and lease acreage efforts, also consider expanding the share buy back program or are the incremental returns in your drilling program such that that’s where the capital would go to, to the extent you expand the capital budget?

Jon S. Brumley

Right now the share buy back program we have approved $50 million and we’ve bought back $40 million or about $39 something million. We weigh all of that. I think that right now we are going to finish the share buy back program and we are going to increase the budget and after we finish the share buy back program we may approve another one.

Operator

You have a follow up question from Scott Loomis.

Analyst Scott Loomis

Ben, one quick question, any update on your quest to find a CO2 source in the Rockies?

L. Ben Nivens

Nothing specific that we’re going to talk about but we’re moving forward on that and at a pretty good pace I would say.

Analyst Scott Loomis

Are you guys still encouraged to hope to lock something up by this year or is that looking like next year?

L. Ben Nivens

That’s still one of our goals.

Operator

You have a follow up question from Noel Parks.

Noel A. Parks - Ladenburg Thalmann

Just had a couple more things, we don’t hear you talk much about the New Mexico and I just wanted a bit of an update on what you’re seeing there. If I remember right you had the first great well last year and maybe a few issues with the subsequent ones and it sounds like these last few have been going positive and just wondering how or what you attribute the upside surprise on those well rates to?

L. Ben Nivens

Noel, it’s just a matter of each individual project is a stand alone project and so you can’t completely predict in any regular order that these wells are going to come in and we had the one big one up front. We had some decent ones and then we had some poor ones and these last few ones have really been good ones and we’re continuing to see wells that aren’t quite online yet that we think are going to be good wells as well. Again, they’re all stand alone projects so you’re going to have some bumps in the road from time to time. But overall it’s a great program. We’re very excited about it.

Jon S. Brumley

It’s a geologically driven conventional play and when you find them they are great and when you’re chasing these morrow channels and sometimes you think you’re going to drill one and you miss it. So it’s just a much more lumpy type of a program than most of the programs at Encore and that’s why we keep it at one rig. We can do a good job with it at one rig. I think that if we expanded it too much you would see us lose that quality so we’re maintaining a one rig program there.

Noel A. Parks - Ladenburg Thalmann

Do I remember you talking about shooting seismic out there for that area?

L. Ben Nivens

Not for the morrow or Toca play.

Noel A. Parks - Ladenburg Thalmann

Are you doing anything in that more recently acquired acreage of the [Lee County] position?

Jon S. Brumley

Yes, that’s where a lot of the drilling is.

Noel A. Parks - Ladenburg Thalmann

Okay. The most recent drilling is on that new acreage?

Jon S. Brumley

Are you talking about the ExxonMobile end lease?

Noel A. Parks - Ladenburg Thalmann

Yes, the end lease.

L. Ben Nivens

No we have not spud that well. That is on the drilling schedule that we will spud that first well here pretty soon and that’s probably the area you’re talking about. We have looked at 3-D seismic there to help us identify some of the plays.

Noel A. Parks - Ladenburg Thalmann

Just one last thing, if you could talk a little bit more about the outlook for the cost progress in the Bakken. I know you talked about in the press release the RORs you were seeing based on what you’ve drilled so far and just have a sense of where you currently think the cost might get to?

Jon S. Brumley

It’s just different with different areas. As we go into new areas we think it will get more economic. Some areas the wells, the best well you can drill for the best economics is a $3.7 million well. In another area you might decide running a liner is more important and you’d rather drill a $4.4 million well. So it just depends on the area and what makes the most sense. We’re not trying to drill the cheapest wells in the play, we’re trying to drill the most economic.

Operator

Your next question comes from Mitchell Wardschmidt.

Analyst Mitchell Wardschmidt

Just had a couple quick questions, most of my questions have been answered, on the refrack program how do you think those refracks, how much do you think those enhance the recovery of the well?

L. Ben Nivens

Jonny mentioned the rates; we went from about 60 to 130 barrels. We think we have the potential for 75,000 to 150,000 barrels reserve on these refracks but we’re still early on. It could be better than that but that’s what we think right now.

Analyst Mitchell Wardschmidt

Are you guys planning to test or do anything with the three [forge sanisans]? I know there’s been a couple operators talking about that? Any thoughts towards that?

Jon S. Brumley

Yes, we have some of those [sanis] wells budgeted for 08.

Analyst Mitchell Wardschmidt

Do you know roughly how many?

Jon S. Brumley

No. I mean somebody here does, I don’t.

Operator

Your next question comes from Matthew Kogan.

Analyst Matthew Kogan

Just a quick question regarding the trading of the units, the ex dividend date showing on the system this morning I think it was May 7th yesterday. Is that correct in terms of the ex dividend date? Do you know in terms of your press release?

Jon S. Brumley

Yes, that’s correct.

Analyst Matthew Kogan

It is correct. So it went ex yesterday?

Jon S. Brumley

Yes.

Analyst Matthew Kogan

Do you have any comment about any future capital raising that you may need to do or equity capital raising in the near future?

Jon S. Brumley

We’re not planning on needing any capital. I think the next capital that we would be if we need to raise capital at Encore Acquisition Company to do it with a drop down and then go raise the equity at Encore Energy Partners.

Operator

You have a final follow up question from Pavel Molchanov.

Pavel Molchanov - Raymond James & Associates

Just a quick housekeeping item, on your daily net profits interest is that still sensitive to some extent with oil prices or has that basically leveled off?

Jon S. Brumley

It has leveled off but it still is sensitive because the higher the oil prices, the less barrels they need to pay the LOE so the more barrels that they take out of production.

Pavel Molchanov - Raymond James & Associates

So the 1,900 to 2,300 guidance for Q2 is that based on future strip?

Jon S. Brumley

Yes.

Thanks everybody for being on the call. Obviously we’re very excited about everything that’s going on at Encore, excited about this TMS and the Bakken keeps getting bigger and better and it’s a great project, it’s fun to work on and then it’s good to see our production beating guidance and we’re really looking forward to the second quarter and think we’ll have a lot of things to talk to you about on that. So everything is moving along pretty well and thanks for being with us.

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Source: Encore Acquisition Company Q1 2008 Earnings Call Transcript
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