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Executives

Jonny Brumley - President & CEO

Analysts

Tom Gardner – Simmons & Co.

Joe Allman – JP Morgan

Steve Berman - Pritchard Capital

[Adrel Asqu] - Hartford Investments

Noel Parks - Ladenburg Thalmann

Adam Like - RBC Capital

[Brian Cusma – Wise Smart Strategies]

Cory Garcia – Raymond James

Encore Acquisition Company (EAC) Q4 2008 Earnings Call February 11, 2009 10:00 AM ET

Operator

Good morning. Welcome to the Encore Acquisition Company and Encore Energy Partners LP conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer period.

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 a 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, Mr. Jonny Brumley. Thank you. Mr. Brumley, you may begin your conference.

Jonny Brumley

Thank you. Thanks for call today. In the room with me to help answer question-and-answer session is John Arms. John is our Senior VP of Acquisitions. Our Senior Vice President of Land is Kevin Treadway, he is also here. Greg Barnes is our VP of the Northern Region and Bill Frances is our VP of the Southern Region.

They are both in here too. And Ben Nivens, our Chief Operating Officer is in the room. Bob Reeves, our CFO is also in the room, and then Jon Brumley, our Chairman is here. And Kim Weimer, our Manager of Investor Relations is here.

I would like to start off the call by saying that 2008 was a good year for Encore from a production and cash flow standpoint. I would also like to point out that we think fourth quarter ’08 guidance by over 1,800 barrels of oil equivalent per day. Guidance was 40,000 BOEs per day and the actual production was 41,824 per day.

Due to a combination of higher prices and higher production, EBITDAX grew to $800 million for 2008. 2008 was also a good year because we were able to hedge 90% of our oil production at $95 per barrel for 2009. These hedges, accompanied with our efficient budget, will allow us to generate $200 million of free cash flow in 2009. This all took foresight in 2008.

I don’t want to spend time reiterating the press release because I want to talk to you about the reserves, the CO2 opportunity and our 2009 plan.

We’ll begin with the reserves. In 2008, reserves went from 231 million barrels at December 31, 2007 to 186 million barrels December 31, 2008. The changes are as follows. We started with 231 million barrels. Then production reduced reserves by 14.4 million barrels.

Acquisitions increased reserves by 1.3 million barrels, and the capital budget added 20 million barrels. Forecast revisions were only at -400,011 barrels, but financial revisions were -52 million barrels. And that leaves us with 186 million barrels as of December 31, 2008.

At first glance, this looks negative, but simply put, we were not making enough money with high-pressure air injections. I feel like now is the time to put pressure on the company and management to contract for CO2. The prize is bigger and the rate of return will be higher.

For now, let’s focus on the 52 million barrels of financial revisions. Revisions due to lower prices and higher op costs were -21 million barrels or 9% of our total 2007 proved reserves. These are the types of revisions that the entire industry is witnessing.

And these are unrelated to the high-pressure air injection project. When prices dropped from $96 per barrel, to $44 per barrel, our long-life oil fields hit their economic limit and they hit it much sooner than the previous year. And the consequence is you lose your tail-end reserves.

December of 2008 was a bad month to be running the year-end reserve report. Not only were prices down year-over-year, LOE was higher and differentials were wider to NYMEX. So, as you would expect, this combination of negative factors cost 21 million barrels of financial revisions due to price.

Now, we’ll switch gears and we’ll talk about the other 31 million barrels of financial revisions. These revisions are associated with our high-pressure air injection project at the Cedar Creek Anticline. I also refer to high-pressure air injections as HPAI, so if I mentioned that, that’s what I mean by HPAIs. I mean high-pressure air. These revisions are due to price and a change of focus by the company to CO2 oil recovery.

The 31 million barrels of high-pressure air injection revisions can be further broken down into two parts. Part one is high-pressure air injection reserves from projects that are already implemented. And these projects represent 21 million barrels of reserves or 9% of our reserves. Since implementing the last of these projects in 2006, a couple of things have become clear. The first one is that HPAI would have ultimately recovered the reserves booked on these projects, but because of the smaller than expected incline in production, it would have taken a long time.

The second reason is the high fixed expenses associated with high pressure air were eating up the margin. To put this into prospective for you, the lifting cost in the panel high-pressure air injection project was $43 per BOE.

And then the Little Beaver project was $21 per BOE. So, at $30 to 40 oil, you can see that the margin has not only been captured, but it’s been devoured. By putting these fields on water floods, we can lower the lifting cost to $13 per barrel. And that will increase annual operating income by $5 million.

So if we are running the company to make money, this is what makes the most sense. And it was an easy decision. By shutting the high-pressure air injections down at panel and Little Beaver, we’re actually going to make more money.

Now, we’ll transition from the high-pressure air injection projects that have been implemented to discuss the 10 million barrels of reserves that capital has not been invested. And obviously Encore has not had any production associated with these because the projects haven’t been implemented.

But if we’re shutting down our current high-pressure air injection project and we believe we’ll make more oil and a better rate of return with CO2, we should remove the unimplemented projects off the proved category and off our books.

We still plan to ultimately recover these barrels from the Cedar Creek Anticline. The CO2 opportunity will be re-classified to probable reserves, which in total represent 70 million barrels of up-side on the Cedar Creek Anticline for CO2.

We feel more comfortable with CO2 for the following reasons. First, we have CO2 pilot which recovered 17% of the residual oil in place in South Pine.

Second, CO2 is more conventional and has been successfully implemented in many different basins, including the Williston Basin and the Powder River Basin, which that’s where our largest CO2 opportunities reside.

And third, with the increased awareness by the general public and the new political regime in Washington, reducing CO2 emissions has become a large focus. We currently have meetings scheduled with the governors of both Montana and Wyoming to discuss how our fields can reduce greenhouse gas emissions in their states.

This next point is very important. We have discussed the new reserve report with our lead bank. And they will recommend leaving the borrowing base unchanged at $1.1 billion. Basically our reserve volume dropped, but our PV did not drop much. Arguably, it may have increased because our operating cash flow is actually going to be higher. I think what’s important about this is this drives home the fact that our core business is still intact.

In summary, without the 31 million barrels of high-pressure air injection, financial revisions would have kept reserves relatively flat. But 31 million billion barrels of high-pressure air injection proved reserves will be replaced by 70 million barrels of probably reserves. Even though these reserves are probable, they have a higher value than the HPAI reserves because the CO2 reserves will be produced sooner and at a higher margin.

Our other core properties that made up 98% of our fourth quarter production held up very good to a huge drop in oil prices, widening differentials and peak commodity cycle operating expenses. This reflects the true quality of our underlying reserve base here at Encore. And that is why we feel confident heading into 2009.

I’d like to stress this. Because we are shutting down the air projects, we do not see production dropping due to this. We will be able to maintain this same amount of production with water flow.

Now I’d like to discuss out 2009 corporate plan. The plan is simple and adds value to the company by focusing out capital dollars on the most efficient and highest rate of return projects. What we’ll set out to do in 2009 is keep production relatively flat. We’ll do this by investing $310 million and that will generate $200 million of free cash flow. Right now, we use the $200 million to repay debt. I think this is a safe plan.

We’ll invest 275 million into drilling and 35 million into land. That adds up to 310. I think it’s important for you to know our corporate objectives for 2009, and they are as follows: keep production flat, generate $200 million of free cash flow, and generate a 15% rate of return on the 2009 capital budget.

We’re also focused on reducing LOE by over 10% and dropping drilling cost in the Bakken by a million dollars per well. At Encore, we like to do at least one project that adds significant value every year. In 2006, we entered into the ExxonMobil JV. In 2007, we entered into the Bakken.

And in 2008, we got started in the Haynesville. And now, in 2009, the big project that we want to do is to procure CO2 at the Cedar Creek Anticline or Belle Creek or at the very least, do an additional CO2 pilot in Belle Creek. And that’s exciting because that’s ultimately going to lead to 200 million barrels of potential.

Now let me give you a brief operational update because we have three key wells drilling or waiting on completion. The first one is we’ll be fracture stimulating a Bakken well on February 19th. And this is an important well because it’s actually flowing 180 barrels a day un-stimulated, and that is very, very unique for the Bakken. And that usually shows it’s going to be one strong well.

On February 16th, we’ll be completing our first Haynesville well. We’re really excited about this. We have a good horizontal drilling team and I’m really proud of this team because this well drilled in the top 30% of Haynesville wells drilled to-date.

And it’s our first one. So said another way, 70% of Haynesville wells have taken longer than our first one. It’s great to enter a new area and have it drilled well and have it drilled on budget. We recently moved the rig and spun our second Haynesville well, and again, we’ll be completing that on February 16th.

The third exciting well we’ll be completing in the first quarter is in the Block 16 in the west Texas JV. Now, if you remember back to the third quarter of 2008, we completed a big well in block 16 called the pioat 3-3, which produces out of the Montoya formation.

And that came on at 13 billion cubic feet per day. We offset that well on December 16, 2008. So we’re very excited about the opportunity in Block 16. Even though our budget is small for 2009, it’s going to be filled with high-impact wells like the three I just mentioned.

Another area that we’re really excited about and will be testing in 2009 is out Bossier play and Statten field areas in Shelby county Texas. In 2008, we had a great Travis Peak program. And in 2009, we’ll test the deeper horizons. The Bossier play is really picking up steam in this area.

It’s 12,200 feet deep, which is just 2,400 feet below our Travis Peak, but recent activity has been big. There are some 15 million a day wells and these are vertical wells and they’re offsetting our acreage. We have 3,300 acre block. It’s a good acreage block, contiguous. We own it 100% and operate it. So we’re really excited about this.

Now, let me fill you in on the TMS play. We brought on our third well and it came in at over 500 barrels a day. So, we’re pretty pleased with that, and that was encouraging. I think the problem with this play that we’re seeing is that the wells cost over $11 million when you include our trouble time.

And right now it’s hard to keep drilling those in a $40 price environment. I think if we do anything in TMS, it will be towards the end of 2009 and when we’re more comfortable with the budget and seeing how the free cash flow has paid down debt.

So I think we’re just going to be cautious. We’re excited about it and we’re excited to see that rate. It’s also time for us to go back and do more science on this. We need to do more science on the completion and relook at our drilling and different ways to drill these wells and maybe figure out a way to drill them more efficiently. But we were encouraged with the rate.

I don’t want to end the call without mentioning a few of the positives in 2008. We grew production fourth quarter ’07 to fourth quarter ’08 by 11%. And that’s all through the drill bit. We also really established ourselves as a key Bakken player by leasing 300,000 acres.

We built an inventory of 18,600 acres in the Haynesville and also the west Texas JV with ExxonMobil has really been going well. They have been a good partner. We finished the year with 30% over budget on our production. So we are estimating to finish the year at 21 million cubic feet per day. And we exited at 27 million cubic feet a day.

We’re bringing some big wells on in Pegasus and Block 16. We expect the west Texas JV to continue to out-perform. And then we’re also excited about this Bossier play.

I’d also want to mention that because of our long-life properties and our hedging plan, Encore is positioned to do well in this commodity environment. We will end 2009 with an ongoing play in the Bakken, the Haynesville, the Bossier, and the west Texas JV. And what is also important to note is that we’ll have less debt and a new CO2 opportunity.

Now, we’ll discuss Encore Energy Partners. In the fourth quarter of 2008, we were able to move some hedging gains into 2008, thereby allowing the partnership to distribute $0.50 per unit for the fourth quarter, which was $2.00 on an annualized basis. Now, due to the quality hedges that we have in place for 2009 and 2010, we can distribute at least $0.50 for a quarter for 2009 and most likely 2010. For 2009, we expect production to stay very flat, and that’s only with $7 million of capital.

Now, we’ll open the call up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question today comes from Tom Gardner with Simmons & Co.

Tom Gardner – Simmons & Co.

Morning, guys.

Jonny Brumley

Hi, Tom.

Tom Gardner – Simmons & Co.

Hey, Jonny, I wanted to ask you at the Cedar Creek Anticline what Encore may have learned through high-pressure air injection. Why the underperformance, I guess, versus your expectations? What is it about the reservoir that may have driven that?

Ben Nivens

Hi, Tom, this is Ben Nivens. I think we had trouble with injectability of air in some areas. We also had more trouble though with premature breakthrough in certain areas. And I think also in panel, the water flood was a very deficient water flood and we just didn’t see the big uplift over air that we thought we would see. I think we learned that the water in certain areas the CCA did a very good job.

Tom Gardner – Simmons & Co.

Your release indicated that you think the costs for CO2 might be more favorable than high-pressure air injection. Just what are your thoughts here? What were you paying for air versus a likely market for CO2 in the area?

Ben Nivens

I think it really goes to the fact that we think CO2 is going to be much more efficient than air and that your uplift is going to be more significant; and therefore, your incremental costs per barrel are going to be cheaper.

Tom Gardner – Simmons & Co.

I got you. You indicated that the reserves will come back on the books when you have a CO2 contract and a successful production response. Is that in the area or in the field proper that you need that successful pilot?

Ben Nivens

That’s going to be both the area and the field. In the area alone we think we have 60 million barrels of potential CO2 reserves that are associated with those air projects. About 20 million are probable and about 40 million are possible. Across the entire Cedar Creek Anticline, there’s 70 million probably and about 200 million of total potential reserves.

Tom Gardner – Simmons & Co.

Can you kind of walk us through the timing? You mentioned that you had a success at South Pine in the way of a CO2 pilot. Can that be used to add back these reserves as proved at some point?

Ben Nivens

It certainly can. The CO2 pilot was in the U4 zone, which is the biggest producer and when we talk about probable reserves, we’re categorizing the U4 CO2 reserves as probable. And we think that with a successful pilot when we get a CO2 contract and we will probably book some reserves. But we will book them associated with the first flood that we intend to do. We won’t put all 70 million barrels on at once. We will put them on as we begin to implement the actual CO2 floods.

Tom Gardner – Simmons & Co.

So can you give us a better idea of what that timing is likely to be? How long did HPAI take to respond? And what do you anticipate for a CO2 pilot?

Ben Nivens

The CO2 will probably start initial response within a year and peak response within two to three years, but I think from the time between signing a contract and ejecting CO2 is something between 18 months and two years.

Tom Gardner – Simmons & Co.

I’ve got it. Thank you, guys.

Jonny Brumley

Thanks.

Ben Nivens

You bet.

Operator

We’ll take our next question today from Joe Allman with JP Morgan.

Joe Allman – JP Morgan

Thank you. Good morning everybody.

Jonny Brumley

Good morning Joe.

Joe Allman – JP Morgan

Jonny or Ben, I guess, in terms of the negative reserve revisions, just at the HPAI program, so you had 31 million BOE and then 21 million BOE was already implemented. Ten was not. So I’m assuming that ten of that 31 was booked as PUDs. And what about the 21 million BOE? Were they all proved developed or were some of those PUDs too?

Ben Nivens

This is Ben again. All of the 31 million barrels were PUDs. The SEC requires you, even though the project is implemented, requires you to categorize the reserves as PUD until you see response. So 21 million barrels were reserves waiting on response in implemented areas and 10 million were PUDs in which no capital has been spent.

Joe Allman – JP Morgan

Okay, that’s helpful. And then if you turn to the other 21 million BOE of negative revisions, there were nine HPAI. How many of those were proved developed tails, PUD tails, or just PUDs that go knocked out?

Ben Nivens

Okay, about 16 million were proved developed tails. About 5 million were associated with the PUDs. About 2 million of that were PUD tails and about 3 million of it were PUDs that no longer ran.

Joe Allman – JP Morgan

Okay, that’s very helpful. Thank you. And then I guess you mentioned some of the HPAI projects that are still on the books. Maybe you said it but I missed it. What projects are you going to continue and which are staying on the books?

Ben Nivens

Okay, none of the HPAI reserves are going to stay on the books except in the form of proved developed. We believe that whatever has been moved to proved developed we will preserve through water flooding. We will begin to shut down the worst patterns immediately in the high-pressure air area. And we will eventually only keep the very best patterns going. But probably that will take over a year, year-and-a-half to completely wind down the high-pressure air.

Joe Allman – JP Morgan

I’ve got it. So is there anything that’s going to happen in 2009 that will help you add reserves? Will any incremental water flooding help you out in reserves in 2009?

Jonny Brumley

Signing a CO2 contract could help us out in reserves.

Joe Allman – JP Morgan

I’ve got it. And I guess you guys have been searching for some CO2 supplies for a while now. Can you talk about the process at this point and what gives you confidence that you might be able to sign something this year?

Jonny Brumley

You’ve just seen a drastic switch in attitude towards CO2. You’ve seen it from the state government, the federal government, and also from the admitters where I think now the CO2 admitters are finally realizing that if they have any chance for expansion, they’re going to have to have a CO2 plan.

So any power plant that needs to expand is calling us wanting to talk to Encore about putting their CO2 into our fields. Also, I think that you’re getting more of a push from the general public as well. So you’re really starting to see things change where we’re producing, and we think we can take advantage of that.

Joe Allman – JP Morgan

I’ve got it. That’s helpful. And then last thing, Jonny, in terms of the free cash flow, is your plan just to pay down debt with that, or do you also plan on buying back stocks?

Jonny Brumley

At the beginning of the year, our plan is mainly to pay down debt and move that potentially to stock repurchases as we’re more comfortable with the debt pay down or we’re more comfortable with our program in 2009. But if we don’t get that comfortable with it or if prices are lower, we’re going to keep it as debt pay-down.

Joe Allman – JP Morgan

Okay, that’s very helpful. Thanks everybody.

Jonny Brumley

Thank you.

Operator

Our next question today comes from Adam Like with RBC Capital Markets.

Adam Like – RBC Capital Markets

Good morning. A couple of quick follow-ups first, of the 21 million barrels that were revised out, what kind of price or cost matrix would you need to reclassify those as proved?

Jonny Brumley

Well, I think obviously you said it right. It's a combination of price and cost. Costs are definitely going to come down this year. You know we're not sure what price is going to do. But I don’t know what it would take to get all 16 million barrels; obviously that is the difference between $96 and $44 at $96 operating cost.

Adam Like- RBC Capital

Okay, so with current cost assumptions and what you're seeing today is continuing, do you have any idea at what kind of pricing you would need to put some of that back on? Is it closer to 90 something or is somewhere?

Jonny Brumley

I think it is at least over 60.

Ben Nivens

Yes but there is more leverage to the down side as prices begin to increase. You get a diminishing return as prices increase because you're enhancing your margin with your operating leverage. So as you moved, you know, probably the $55 to $60 level a lot of it would work.

And just kind of my gut tells me that because we've been operating at $60 price environment for many years and no big revisions. And so then probably from $80 to $90, it's not very many reserves. Because you've already got those back on the books.

Adam Like- RBC Capital

Okay. And then just going through the x-revisions still looks like finding costs were pretty high. Is there, you know, something from the drilling program flow over into '09 that would add significant amount of new reserves that we should see that expect to smooth out the curve? Or could you give us some more color on your high cost?

Jonny Brumley

We expect finding costs to drop significantly in 2009. First off the TMS increase F&D costs quite a bit. And then the acreage, we added a 170,000 acres in the Bakken and that increased finding and development costs as well.

This year will be a much lighter year as far as land and less money will be invested in the TMS. So that's going to bring them down a lot.

Ben Nivens

And drilling costs obviously went up a lot and between drilling costs and some of the troubled times that is associated with a busy environment and a very active drilling schedule those two things together I think cost us about $5.

And as Jonny mentioned, TMS cost us a fair amount too. And then we had an extremely active land program.

Jonny Brumley

Yes, I mean I think TMS was like $4 or $5, drilling just increased, drilling costs was $5, and then you have the land. I'm not sure what that but it had to be significant because we bought a significant amount of land.

Adam Like- RBC Capital

Okay, that's great. And then real quickly you've talked around the CO2 stuff, are you anywhere in process of negotiating a contract and also do you have any estimates of what operating costs might be? Or is that way to premature?

Jonny Brumley

That's not too premature for us, I mean we know that. As far as operating costs go, I don't think it would be smart to talk about it on a conference call while we're trying to buy CO2 and we are currently talking to a lot of people about purchasing CO2. So it's pretty exciting time for us.

Adam Like- RBC Capital

Okay one last quick one. You've got a reaffirmation of your borrowing base, any expectation that could change or is there any risk of that could change with the spring redetermination?

Robert C. Reeves

Well, what we're doing is we're going to bring the spring redetermination up is what Jonny was alluding to. So we've went to the banks, you know, a couple weeks ago and started talking to them about potentially moving it up. But we've actually went through the beginning of that process and we'll try to get it completed in the next two or three weeks.

Adam Like- RBC Capital

Okay, thanks a lot.

Operator

Our next question comes from Noel Parks from Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

Good morning.

Jonny Brumley

Good morning, Noel.

Noel Parks – Ladenburg Thalmann

Had a few questions. I wanted to move up to the Bakken. If I understand this press release right it looks like the primary target at Almond will be the Sanish?

Jonny Brumley

That's correct.

Noel Parks – Ladenburg Thalmann

And has there been any other activity near there by the industry that either pointed you to the Sanish or led you to decide that is what you wanted to target mainly?

Jonny Brumley

Well, there's been activity in both the Sanish and the Bakken and in the near area. You got to remember it's such a big area that we are talking about. We've had operators within several miles of our acreage make good wells.

We also are – the well that we are currently drilling is a re-entry that was a detest that another operator did. And the Sanish showed up well in that. So that's why we targeted the Sanish here.

Ben Nivens

Yes, we actually had a log and a core across the Sanish from the deeper exploratory well that wasn’t Bakken or Sanish related. And so we are able to purchase that well and re-enter it, mill out a window, and then drill a horizontal lateral into the Sanish. So we are excited about that and that was a cost effective way to test this area.

Noel Parks – Ladenburg Thalmann

Okay, got it. And what sort of – I don't know if this is something you feel comfortable talking about but what sort of lateral length are we talking about? Is it similar generally to what you've done in your early drilling, further south and west in the base?

Jonny Brumley

Yes we're currently going to drill a 640 here which is around 5,000 feet. And but I'm sure we'll try some 1280's as well.

Noel Parks – Ladenburg Thalmann

Okay.

Jonny Brumley

It's very similar to the rest Bakken.

Noel Parks – Ladenburg Thalmann

Okay. And also in the same base but different project, the high pressure air project I know that you guys have been talking less about that over the last couple years. Did you have any significant engineering talent really dedicated to that over 2008? And if so I was wondering have they been redeployed and wondering to where?

Jonny Brumley

Yes, the answer to that is yes. Because the Cedar Creek Anticline is our biggest asset and we have you know a lot of manpower that works on the Cedar Creek Anticline including the water plugs end and the air projects. But the same people that were working on the air is going to be working on the CO2 projects as well.

Noel Parks – Ladenburg Thalmann

Okay and as far implementing water, flood and some of the former high pressure air fields, just so I understand do you have infrastructure in place from Anticline flooding so it's just really a matter of, I don’t know, expanding patterns or maybe doing some work on old injector? Or are you going to be basically starting from scratch with some of these areas?

Jonny Brumley

No, you were right the first time. These are old water floods. They were enhanced the pattern wise by the high pressure air. Many of the high pressure air injectors will be converted to water injection. There are still some water injection wells in the area.

Noel Parks – Ladenburg Thalmann

What sort of cost are you looking at for that conversion and what sort of time frame are we talking about between ending the high pressure air injection, doing the transition, getting the flood on line, and then ultimately seeing – hopefully seeing a response from the water flood?

Jonny Brumley

The cost will be fairly minimal this year. It will probably be around $2 or $3 million. And that will be – we'll work that in as part of our overall $310 million budget. In 2010, we're still working out the details but it will be $7 to $10 million probably.

Noel Parks – Ladenburg Thalmann

Okay and the time frame?

Jonny Brumley

We will begin converting some patterns very quickly. And then by the end of the year we will probably have all the patterns except the very best air patterns converted to water. And then we will watch those and shut those down more slowly.

Noel Parks – Ladenburg Thalmann

Okay.

Ben Nivens

We've also have beefed up our tertiary team. Tom Olle is heading up the commercial side of that team. We're excited about that. And Tom is a great engineer and then Bob Sutherland is one of our brightest engineers. He's really heading up the technical side of the CO2 team. And then we have a very good engineer at the Cedar Creek Anticline that handles that named Melvin Foster who's doing a good job. And then we have about three engineers working with them.

So we've got you know – I don’t want you to think that we've just going status quo from high pressure air to CO2. We're putting a lot of manpower on this. And we're very excited.

Noel Parks – Ladenburg Thalmann

Okay, great. Do you have any thoughts on the acreage acquisition environment in the Bakken now that we've seen the pull back in prices and in drilling rig activity up there?

Jonny Brumley

The acreage has dropped somewhat in value. I don’t think that your going to see us really putting together big acres positions. What we're about is we're in some really good areas and we want to improve and just grow the areas that we're in.

Noel Parks – Ladenburg Thalmann

Okay. And I think my last one, looking at the Tuscaloosa Marine Shale, so the last well was 500 barrels a day and you did say it was a little bit of trouble time involved that got into the cost of the well – the total cost of the well.

I do remember you saying in that past that you needed about 400 barrels a day or better to feel like the play was worth pursuing. Given what you had in terms any difficulties on the well maybe you could talk about that? Is that 400 or better threshold still what you are thinking or is the 500 that you saw now sort of the minimum you need to see going forward?

Jonny Brumley

Well, it's all relative to oil price too. At $100 oil, which we had back in September of 2008, you get a lot more cash flow and the prize was more valuable to tip around something pretty difficult like the Tuscaloosa Marine Shale.

At these prices it's more difficult because you don’t have the access cash flow. Because we don't have the access cash flow, we're more focused on repaying debt and so it's just a little bit different right a different time.

Noel Parks – Ladenburg Thalmann

Sure, do you have a sense of – assuming that we see some improvement in crude prices, let's say $60 a barrel for argument? Do you have a sense of about what size well's you need to see once you start up again there to feel good pursuing it?

Jonny Brumley

I think that we have a size enough well to where you think this project has a lot promise. It's just are you going to have enough cash flow to work on it. It think that's more of the question not – I mean this – if oil was where it was in September when we got a 500 barrel a day rate we would be very, very, excited.

Noel Parks – Ladenburg Thalmann

Sure and just one last thing. Is most of the acreage out there is that held by production, your 200,000 acres out there, the TMS play?

Jonny Brumley

No. But we're not going to lose hardly any acreage in '09. Now 2010 just really a tiny amount expires then. So we're really pretty good until 2011, 2012.

Noel Parks – Ladenburg Thalmann

Okay, great that's what I wanted to know. Thanks a lot.

Jonny Brumley

All right. Thank you.

Operator

Our next question comes from Steve Berman with Pritchard Capital.

Steve Berman – Pritchard Capital

Good morning.

Jonny Brumley

Hi Steve.

Steve Berman – Pritchard Capital

Let me start with a follow-up on TMS. What should these wells cost when we're passed the signs project stage on some sort of normal basis relative to the $11 million you cited earlier, Jonny?

Ben Nivens

This is Ben. I think the cost needs to be driven down to the $6 or $7 million range. And that's going to be the challenge.

Steve Berman – Pritchard Capital

Okay, and a couple other clarifications. Jonny, you mentioned the Bossier earlier. Are we talking about the deep Bossier sand that comes in like con and gas stars had great success drilling vertical wells? Or are we talking because this bossier slate, is it bossier sand I just want to be clear on what your targeting there?

Bill Francis

Hello this is Bill Frances. It's actually there's a bossier shale and right below the bossier shale is a Cotton Valley lime which is also one of our target zones. But it is your right it is developed vertically out there.

Steve Berman – Pritchard Capital

But – so it is a shale?

Bill Francis

That is correct.

Steve Berman – Pritchard Capital

Okay. Then on the CO2, in the past you talked about and have in all of your presentations, a slide that says there's $200 million BOE of CO2 opportunity in the Rockies. Does this change in the reserves going from air to CO2, does that change that number at all? Does that increase it? I mean is there now more CO2 upside?

Jonny Brumley

No.. It stays at 200 million barrels.

Steve Berman – Pritchard Capital

Okay. A Haynesville question, in your experience with the first well in terms of scheduling completions, getting prop and et cetera, there's been some companies that had drilled wells there and had to wait you know quite awhile once they TD once they get a completion started. What's your experience with that first well in terms of things like that? And also relative to what you thought it would cost you?

Ben Nivens

This is Ben. The Haynesville well we planned that well in advance. We planned the casing, which we had to pre-order and the prop-in. So everything was ready to go when the well was TD. And the same was true for the second well. So it just took a lot of planning ahead.

We did see those same shortages back in the fall and that's why we planned ahead.

Steve Berman – Pritchard Capital

What's the length of the lateral on that first well?

Ben Nivens

Forty two hundred feet.

Steve Berman – Pritchard Capital

Okay, last one I think. It looks like you did repurchase some stock in Q4, if I'm reading the cash flow statement right. If that's the case, can you say what – how many shares you bought and what the average price was?

Jonny Brumley

Yes Bob Reeves has that.

Robert C. Reeves

Yes, our average price was $27 a share for that $17 million.

Steve Berman – Pritchard Capital

Seventeen million at $27 a share.

Robert C. Reeves

Right.

Steve Berman – Pritchard Capital

Okay, I think that's it. Thanks, guys.

Jonny Brumley

Thank you.

Operator

Our next question today comes from Cory Garcia with Raymond James.

Cory Garcia – Raymond James

Good morning guys.

Jonny Brumley

Good morning, Cory, how are you?

Cory Garcia – Raymond James

I'm hanging in there. Just a quick housekeeping item in the Bakken, do you have a 7 or 30 day IP rates for your most recent completion, I believe it was three last quarter?

Jonny Brumley

The 30 day IP was around 300 barrel for the last three or four wells that we completed.

Cory Garcia – Raymond James

Okay, and also maybe could you also give some color into where you guys are internally where you need to see oil prices go based on the anticipated decline in well cost to I think it was roughly $4 million later on this year, in order to get more comfortable ramping up from the three rigs your planning on running?

Jonny Brumley

Well, right now we're planning on running one to two rigs in the Bakken in our reduced budget. And those cost savings will hope to see will come from reduced casings costs and reduced stimulation costs, and reduced services that are around the completion as well.

Cory Garcia – Raymond James

Sure, is that really the primary factor before you guys can actually accelerate activity or is there also an obviously a function of being in a really depressed oil price environment as well?

Jonny Brumley

I think it's a little bit of both. If you know if prices were in the $60 range and say your in 2010 and you got your cost down $4 million, you would feel real comfortable running more than one rig.

And that would be – that's a good healthy pricing versus commodity cost scenario. Just right now you have mismatch. And so that just needs to be right.

Cory Garcia – Raymond James

Sure, I really appreciate it.

Jonny Brumley

Thank you.

Operator

Our next question comes from Brian Cusma with Wise Smart Strategies (ph).

Jonny Brumley

Hi Brian.

[Brian Cusma – Wise Smart Strategies]

Hi guys. What was your PV10 in?

Ben Nivens

Our PV10 at year-end was, hold on just a second.

[Brian Cusma – Wise Smart Strategies]

The pre-tax number.

Ben Nivens

It was $1.5 billion.

[Brian Cusma – Wise Smart Strategies]

Okay.

Ben Nivens

With 186 million barrels.

[Brian Cusma – Wise Smart Strategies]

Okay and do you happen to have the split, like what the puts were worth on a PV10 basis?

Ben Nivens

The puts were worth about $90 million.

[Brian Cusma – Wise Smart Strategies]

Okay, and then when you think the – how many reserves were still in the books for high pressure air in (inaudible)?

Ben Nivens

Again the only reserves that are on the books for high pressure air is what is associated with the PDP curve. So it's really PDP now not considered high pressure air.

Jonny Brumley

Yes and so now those reserves would just be water flood reserves for the most part. Because we are converting that high pressure air flow back to water flood and do not think we will lose any production. What we don’t think that this reserve revision with high pressure air is going to affect production at all.

[Brian Cusma – Wise Smart Strategies]

Okay. And so there would be no change in the production profile assumed in your reserve report.

Ben Nivens

That is correct.

Jonny Brumley

That's correct and that's right.

[Brian Cusma – Wise Smart Strategies]

OK, that's what I needed. Thanks guys.

Jonny Brumley

Thanks.

Operator

Our next question comes from Adrel Asqu (ph) with Hartford Investments.

[Adrel Asqu] - Hartford Investments

Yes, can you give me your availability on the revolver as of year end, and what about cash on a balance sheet.

Jonny Brumley

Well, I didn’t hear the second part.

[Adrel Asqu] - Hartford Investments

Any cash on the balance sheet?

Robert C. Reeves

We had very little cash on the balance sheet. We keep a very low cash balance. We just move it on and off the revolver as we need it weekly, but we had $575 million on EACs revolver out of a $1.1 billion availability. So $525 million available on hand.

[Adrel Asqu] - Hartford Investments

Okay. Then what about 2010 hedges?

Jonny Brumley

We're about at 30% hedged at $60 oil for 2010.

[Adrel Asqu] - Hartford Investments

Do you guys make public the market value of the hedges?

Jonny Brumley

Yes, it would be in the 10K.

[Adrel Asqu] - Hartford Investments

What about an updated figure?

Robert C. Reeves

It's about $375 million.

[Adrel Asqu] - Hartford Investments

Okay.

Jonny Brumley

There's a good schematic, a good matrix in our IR presentation that you can look at that will tell you where the value of our hedges are at certain price and areas.

[Adrel Asqu] - Hartford Investments

Okay.

Ben Nivens

For 2009?

[Adrel Asqu] - Hartford Investments

All right. Okay. When you say that your lead bank is going to recommend that you leave your baring base at 1.1 billion, are you meaning that they're going to recommend to you the rest of the bank group or can you come talk through that whole process.

Robert C. Reeves

That's exactly what we mean. We've you know taken it through their engineers and their bankers and they've you know through their internal process reaffirmed that amount. We'll need to go out to all the banks and talk to them and but we don’t see any problems with the reaffirmation process.

[Adrel Asqu] - Hartford Investments

How many members in the bank group?

Jonny Brumley

Twenty two.

[Adrel Asqu] - Hartford Investments

Okay. That's very helpful. Thanks guys.

Operator

We will return for a follow up question from Joe Allman with JP Morgan.

Joe Allman - JP Morgan

I'm actually good guys my question has been answered, thank you.

Ben Nivens

Thanks.

Operator

We have another follow up from Steve Berman with Pritchard Capital.

Steve Berman - Pritchard Capital

A follow up on the hedging question, you had monetized a small piece not too long ago is that something you've been having much in the money that says that you might do again. What are your thoughts on that?

Jonny Brumley

What we currently are thinking about that and I'm not sure that it's going to shake out, because I think that, you know, one of the things is our hedging is so put based. So if you were to re-put on puts, you would actually be having to put more premium in.

So what we're thinking about is if we do this, do we just go ahead and swap it out. I don’t think we would really want to take the hedges off and just go back to being naked again. So you know we are thinking about it. We're not sure what we're going to do.

We do know we're in a good position. So we wanted to-- we would want to make sure we’re enhancing our position by doing this. And so that's really-- we're discussing it but we don’t know.

Steve Berman - Pritchard Capital

Thanks, Jonny.

Operator

(Operator Instructions). This concludes today's questions and answers session. I will now turn the call over to Mr. Jonnie Brumley for his concluding remarks.

Jonny Brumley

Well, we look forward to 2009. We're very excited about this budget, about the debt pay down, about the free cash flow. I think it's times like these when long life properties shine and we defiantly have a lot of those.

I know that we all feel like we're in a very depressed commodity environment but our properties have seen depressed commodity environments, some of them for the past 80 years, some of them for the past 50 years.

So we're not your typical company, and with these types of properties, hold their heads up much better. And with this hedging program, we're really, really going to turn 2009 into a positive year and our company is actually going to be in enhanced throughout this year.

I think that that is unique and I think that that's not many companies can say they're going to be better off in 2009, 12-31-09 than they were on 1-1-09 and I look forward to that. Thanks.

Operator

Thank you for participating in today's conference. This concludes our presentation. You may now disconnect your lines. Thank you.

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Source: Encore Acquisition Company, Q4 2008 Earnings Call Transcript
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