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Encore Acquisition Co. (NASDAQ:EAC)

Q1 2009 Earnings Call

April 29, 2009 11:00 AM ET

Executives

Jon S. Brumley - President and Chief Executive Officer

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

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

Analysts

Joseph Allman - JPMorgan

John Freeman - Raymond James & Associates

Chris Pikul - Morgan Keegan

Steve Berman - Pritchard Capital Partners

Noel Parks - Ladenburg Thalmann

Kevin Smith - Raymond James & Associates

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 current available information.

However, the assumptions by management and the future performance of Encore are both subject to a wide range of 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. Jon Brumley. Thank you. Mr. Brumley, you may begin your conference.

Jon S. Brumley

Thanks. This is Jonny Brumley, President and CEO of Encore. Thank you for being on our first quarter call. In the room with me today is Jon Brumley our Chairman, Ben Nivens, our COO, Bob Reeves, our CFO, John Arms, who is our Senior Vice President of Acquisitions and Kevin Treadway, our Senior Vice President of Land.

Our format is going to be a little bit different today than our previous calls. I'll go over Encore strategy and a few of a highlight, then I'll turn the call over to Ben to go over to operations, and Ben will turn it over to Bob Reeves to go over the financials in the Encore energy partners financial and operations too.

After Bob is finished, we'll open the call up for questions. I couldn't have been more pleased with our production in the first quarter. We averaged 41,900 barrels a day that beat guidance a lot, beat guidance by 1900 barrels a day, makes me feel comfortable with our plan, when I see this type of production especially given the fact that we were -- about $6 million under budget on our CapEx program.

So really we delivered well. We delivered more oil on less CapEx and you can't beat the quarter like that. That's what we say out to do every quarter, so it feels good to actually have done it.

I think before we get too excited about the production, its important to remember what 2009 is all about for Encore. The most important thing that we are trying to do is to maintain the $190 million that we received from monetized in the hedges in the first quarter as debt pay down.

So to do this we have to stay on top of our CapEx -- we have to stay on top of our lease operating expenses. We did a great job of doing this in the first quarter and we just have to continue to do that. And by monetizing our hedges, we are forced to have our expenses in CapEx, match actual cash flow to retain the hedge monetization as debt pay down.

And I think that this is real important because that does increase the tension on the operating group. Now it's really, really that there is not as this where we went a little bit outside of our operating cash flow but we have these $90 hedges so its really not as bad as you think. Look, we've taken those hedges off pay down debt worth it and what we're doing now is matching our CapEx to our cash flow.

We're not guiding -- we're not doing this towards production. What we are about is paying down a $190 million of debt, so I think that's real important for you to understand that, and we're going to be inside of cash flow.

Remember, that so -- just when you look at Encore in 2009, we're trying to enhance the balance sheet and really trying to improve the company. I will say this, this is going to be really unique. There is not many companies that are going to come out of 2009 and better shape than they went in and I feel real good about that, and that's why we're so proud of this plan.

Secondly, implemented this plan we had about $1 billion of debt and $1 billion of market cap, so by reducing debt by $200 million and keeping our production flat

We're moving $200 million from the debt side of the balance sheet to the equity side.

And the important thing is that when you keep your production flat, your net asset value stays the same. And -- so, the only reason why we can't do this and generate $200 million of excess cash flows is our properties don't decline as fast as our competitors.

In this strategy, generated 20% return on equity from paying down debt and you can't beat that because what you've done is you've taken $200 million from the debt side and moved it to the equity side. And your net asset value has stayed the same. You've got $1 billion of equity.

So, this makes a lot of sense. This conservative budget makes a lot of sense for the equity holder and it will add a lot of value.

Another added benefit is we defer our development project, until prices increase and we can generate a good rate of return as opposed to barden through these projects at low prices. And you'll see this even more later, and how important this is. So it makes a lot of sense to do that.

To further enhance, Encore last week we issued $225 million of bonds. It was a net $203 million to the company. This bond deal enhances our already strong liquidity position and now we have very resilient properties, and now we have a resilient balance sheet to match these properties.

Now, let me address the second quarter production guidance, production dropped in about 40,000 barrels a day. The main reason why we have this is we have a Haynesville well is ready to go. But we don't want to bring it on in this $3 gas environment that does not make sense.

So, these wells produce so much in the first three months that you're wasting the economic benefit of this well. When you bring it on right now, the market is telling you that don't want the gas, so it's not smart to bring it on.

We're in this to make money. And that's about 800 barrels a day of the 1900 barrel a day drop. The other large item is 400 barrel increase in the net profits interest that to Cedar Creek Anticline and there is really just nothing we can do about that.

And I think the rest is being conservative. I mean you have to remember where we were in the fourth quarter at 2008, we're running 14 rigs. Now we're only running four rigs. So we're being very conservative in estimating future production because the rig counts drop so significantly, and I think that's only smart.

But bring on big wells in a low price environment, we're not going to do that, especially when there is a good chance prices are going to be much higher in the third and fourth quarter.

So, our production could be higher but we're in this to make money not just production. The second thing I'd like to talk to you about is the three goodwill as we at Cherry. That's really exciting and a healthy focus on that.

Seeing this area work is important into our biggest area in the Bakken. The Brekhus well was a disappointment, that was north to Almond, but not everything works and if you could choose one, I rather choose the one that we had the most acreage.

I don't think you could ask for more from this development program, the West Texas JV is really generating great returns, this better returns in the Haynesville. So if you like the Haynesville, your going to love our West Texas JV. Nobody has it, that makes us unique, and we're lucky to have these big fields and a great partner with ExxonMobil to exploit these big fields. Our Haynesville program has beaten our expectations, so we're proud of that.

And then we're also real fortunate to have the Bakken, as you know, oil prices outperform gas prices. They always have, probably always will and so we feel real fortunate to have the big, big position, and really the only large oil play in the nation. We have more acreage per share than anybody in the play, so we feel fortunate about that.

Before we transition into the operations, I want to talk to you about a few things. The first one is the Cedar Creek Anticline outperforming by 400 barrels a day with no drilling. You can't ask for a better gift than that when you are focused on maintaining your production with very limited CapEx. That's huge.

The second thing is even as good as the Haynesville is, the West Texas JV is better. We are generating bigger IPs for capital there. So we're very proud of that -- permanent results, we like our plans, put simply it takes advantage of our long life properties and adds value during the year when others are struggling.

Now I'll turn the call over to Ben. Ben's, our Chief Operating Officer.

L. Ben Nivens, Jr.

Thank you, Jonny. Encore's operating results for the first quarter as our production team and above forecast in our operating cost and capital investments sort of lower than guidance.

In the first quarter is obviously highlighted by the 1900 barrels above midpoint of guidance on the production, and this was due to several strong wells coming in above the risk forecast and a few big wells coming in, Cedar (ph) going to anticipate coming in the first quarter, they thought they would come in the second quarter.

Let me talk about a few of our areas and I'll start with Exxon JV. So JV averaged 28.5 million a day or barrel of oil equivalent of 4750 barrels oil per day. This represents 11% of our total production and is a big reason for us beating our guidance. And I'll talk about two wells in particular that came on very strong.

The first one is the McElroy Ranch 62H in our Wilshire Field. This is a horizontal well that came on in January, and it came on at a rate of 5.6 million a day with 450 barrels of common site (ph), which when you convert that to BOE/D with 1380 BOE/D.

Its currently producing 5.2 million a day and 170 barrels of common site are still around a 1000 barrels a day on a barrel oil equivalent. And we own almost 100% working interest and 72% NOI (ph) net well.

The Banner Estate 92H in Brown Bassett Field and it's a strong horizontal that came on in December for 5.4 million a day or 900 barrels oil equivalent. It's still producing at about a rate equivalent to 420 barrels oil. And this production has held up better than expected. We have a 86% NOI net well. Both these wells came on stronger than expected and today have declined a less than expected. And we're part of that production being over guidance.

In total in the JV we bought on six wells in the quarter, and we intent to bring on four wells in the second quarter, including a direct offset to the McElroy Ranch in the Wilshire Field.

We have reduced our rig count from five, early in the fourth quarter to two rigs by the end of the second quarter. And we currently still have two rigs going in the JV, but expect to go down to one rig by the end of the second quarter.

Moving on to our Haynesville, it was a exciting quarter in our Haynesville as we brought on our first two horizontal well, one operated and one non-operated. Let me talk about the operated well first, a core this 29 rates. We've mentioned this well before. It's in the Greenwood Waskom Field albeit (ph) 6.8 million a day and production began in February.

We'd originally scheduled this to be a second quarter well. So we have responded with our positive guidance, a positive variants to guidance as well. We have TD our second well, the Dunn well, it's in the Greenwood Waskom, an offset to the core of these.

As Jonny mentioned, we are going to delay that completion to later in the year because of the current gas prices. Another exciting well for us was our non-op well, the Hall 9-1 and Caspiana field.

This well came on in March and produced rates as high 2.7 million a day. The Caspiana area looks to be a very strong producing area in the Haynesville, and we're very excited about that. We have 20% working interest in 18.6% NOI in the well. And the operator is currently drilling two offsets for this well, when we have similar interest -- and those as well. Production from these well will probably begin at late second quarter or early third quarter.

Now moving on to our Bakken, let me correct that the Hall 9-1 came own it at rate 12.7 million a day, how about I didn't say that wrong earlier. Okay I apologize for that, let me move now to the Bakken.

We completed four wells in the quarter, all of them were in the Sanish and results are highlighted in our press release by well. We had three successful wells at average 450 barrels a day for the first seven days of production.

Some of these wells were in our Cherry Creek area, as Jonny mentioned and we're very excited to prove up that area and one was in our Charlson area, which has proved to be our best area in the Bakken.

As Jonny mentioned, also we did have our first Almond test, that was a Sanish three-fourth test and it was unsuccessful. We have drilled our second well but we're still in a process of completing it. It will be a Bakken test and I don't have any results for that that I can share with you at this time.

Overall our Bakken is performing very well. We have reduced our drilling cost. We think our net 640 that we just completed drilling, will be drilled and completed for about $4.2 million that's getting down close to our target of $4 million that we have announced before. We have one rig running in the play in the second quarters and we'll continue to run one rig out there for most of the year.

Now let me move to the Cedar Creek Anticline, as Jonny mentioned, this area exceeded guidance by over 400 barrels on a base reduction and the MPI was another 150 or 200 barrels and we're very excited about that.

A lot -- one of the main reasons for that overage is Coral Creek waterflood is over performing, Coral Creek actually is increasing in production as the waterflood begins to -- continues to show positive response.

We are progressing with our plans to convert our high-pressure air injection wells to water injection wells in Cedar Creek Anticline. We had a total of 42 air injectors and in this quarter the first quarter of '09 we converted 12 of those air injectors in the Pennel, field, both converter -- total of 15 more throughout the year and then we'll convert the remainder of those wells in 2010 for water injection.

By doing so, we expect to reduce our operating cost by more than 15% in these units in which have air injection our total of about a $150,000 a month.

And the company doesn't expect as we've mention before does not expect to loose any production as result of these conversions from high-pressure air to waterflood.

Let me move on to the operating cost, our lease operating cost came in below the lower end of our guidance at an $11.73. This is obviously as result of higher volumes but it is also the result of the company so reducing operating cost.

Our operating cost totaled 42.2 million for the quarter which was lower than our guidance and that included the additional 1900 barrels of production that we were above guidance. We will continue to work on operating cost and as we mentioned before our goal is to reduce our operating cost 8% from fourth quarter of '08 to fourth quarter of '09 and we feel we are well on our way to doing that.

Our capital expenditures came in 6 million below our mid-point of guidance at $124 million, and we reduced our operating rig counts of 15 rigs in the fourth quarter to four rigs by the end of the first quarter of '09.

We're guiding to invest 70 to $80 million in the second quarter and getting our rig count down to this level will enable us to meet our target.

That concludes the operational review, and now I'll turn it over to Bob Reeves to go over the financials.

Thanks Ben. I just want to go over some of key takeaways, regarding this quarter and the financial health of Encore. As Jonny spent -- talked about earlier, we did reduce our debt by net 187 million for the quarter. Likewise in the quarter, we had our borrowing base predeterminations for both EAC and ENP.

The properties reaffirmed their existing borrowing basis at EAC at 1.1 billion which was further reduced for the hedge monetization of 200 million so that reduced the borrowing base to 900 million. On a status quo basis, we had 353 million outstanding at 331, which leaves with you three $547 million available EAC, and ENP was reaffirmed at $240 million at the end of the quarter, we had a $185 million outstanding on it with 55 million available.

So in total we had just over 600 million available on both facilities at 331. These facilities do not mature until 2012 and our next predetermination is not until October of 2009, so we're in good shape there.

Next I've like to go over the bond offerings. I'd just like to stress that we did not issue these bonds because of any indication of a looming borrowing base reduction from our banks or anything similar to that.

We wanted to reduce our reliance on the banks and move into a deep position which matches our conservative nature as a company. These bonds increase our liquidity and extend our maturities this gives us the lot of cushion from the financing perspective, which gives you many options and flexibility down the road.

Let's briefly go over the details of the bond offering. We did issue 225 million as senior subordinated notes at 92.228 with a 9.5% coupon (ph). These are sever year notes that mature in 2016, which fits nicely into our 14, 15 and 17 notes.

The net proceeds from the offering were 203 million and we used those proceeds to pay down debt on our credit facility. The credit facility borrowing base is automatically reduced by one-third the face value of these notes or 75 million.

Our new borrowing for EAC is now 825 million. Pro forma, the EAC borrowing facility has a 150 million outstanding. So that makes it 675 million now available under EAC's or an additional 128 million of liquidity.

On a consolidated basis Encore now has 730 million of cushion and long day maturities on our facility and our bonds. As Jonny stated, our goal is to hold on to this roughly 190 million of debt reduction in the quarter and a stay within our discretionary cash flows for the remainder of the year. We can accomplish this because we don't really have any long-term contracts for rigs or large blocks of acreage that are close to expiring.

We have a stable oil production base as may primarily of waterfloods with a shale production decline profile. So for this reason, we can simply just adjust our capital budget for the remainder of the year and stay within our cash flows.

Lets move over to Encore Energy Partners, I'll give a brief update on the performance of ENT for the quarter. It was another great quarter for ENT, our production was at the high end of our guidance at 6442 barrels a day. Our capital was efficiently invested in own budgets. LOE and G&A were inline with expectations. Our oil differentials tied significantly from level that we saw in the fourth quarter 2008. little differentials averaged to 14% discounts to NYMEX in the first quarter of 2009 versus the 20% discount in NYMEX we saw in the fourth quarter of 2008.

And for the second quarter of 2009, we're expecting it to get even better with around 10% discount to NYMEX.

On the gas differential side, they were wider than we expected similar to what we saw in EAC. The liquids portion of the revenue stream dropped faster than the dry gas portion, and some of this was happening in the fourth quarter that rolled over into the first quarter. So it exaggerated the effect at the first quarter differential. Really the differential in the first quarter was around 20%. But for the second quarter, we expect to see that tightened up as well to around 15% on the gas side.

Our cash available for distribution was roughly 26 million for the first quarter of 2009, as a result of our solid operating performance and our outstanding hedge portfolio. We plan to distribute $0.15 per unit this quarter or 16.8 million, the remaining 9 million will be used to reduce debt.

At the end of the quarter, we had an 185 million outstanding on our $240 million revolving credit facility.

Our partnership has differentiated from the rest Paxton inception (ph) because of our business strategy. We seek to acquire these long life properties with the borrowing characteristics. Long lives, shale declining, margin stable (ph) and its really paying off.

We only invest development capital to maintain the production base through projects with the higher rate of return and seek growth only through acquisitions. We combined this with a savvy hedging strategy that seeks to protect two-thirds of the downside risk, well allowing investor exposure to two-thirds of the upside from commodity prices.

When commodity prices eventually rebound, we will have a flexible and variable distribution philosophy that will return more cost to the unit holders. ENP has a strong parent sponsor to EAC which is an another key to our success. We believe this business strategy will prove to be the best strategy over the long run for all types of commodity price cycles. ENP has clearly differentiated itself in the NLP world as the premier upstream NLP.

With that, I'll turn back over for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Joseph Allman with JPMorgan. Please state your question.

Joseph Allman - JPMorgan

Thank you and good morning everybody.

Jon Brumley

Good morning. How are you?

Joseph Allman - JPMorgan

Good. Thanks Jon. Hey, at the Almond prospect in the Bakken. So I might have missed what you said Ben, you plan of joining any more there and or -- does this well give you a lot of less encouragement about the perceptivity in that area?

Jon Brumley

Yeah. It was a dry whole, so it gives us a lot less encouragement. We have one well drill to the south that we are currently completing or about to complete. But we are more negative on this than we were prior drilling this well or prior to completing this well. But, we are pleased with the Cherry prospect getting three good wells in there.

Joseph Allman - JPMorgan

So the Cherry, if I'm not mistaken the Cherry you've got over 77,000 net acres at Almond, you've got over 65,000 net acres. I mean do you think, based on what your seeing in the second well, do you think even to the south it's not very good. So I mean as far we're concern maybe just zero out the Almond and any kind of value on the prospect?

Jon Brumley

No, I wouldn't zero it out yet. I would wait for this well to come in, and then we've had some good wells to the west of that acreage, so that could help. And then on this big of an acreage block just to zero it out on one or two wells, I don't think would be smart but I do think you shouldn't -- you should start risking it more because of these two wells. It's obviously hasn't gone up in value. It's dropped in value but it certainly not at zero.

Joseph Allman - JPMorgan

Got you. In the Bakken, just overall what's like in the first quarter you averaged just under 2800 BOE/D. Could you talk about how your sending that oil out, is it pipe -- your trucking it, your railing it and kind of what capacity you've got for all those things and just comment on this differentials and what not recently?

Jon Brumley

We have plenty of capacity. We do truck some of our oil but that simply steal trucking, its trucked to pipeline terminals and then piped out of the basin nothing where we have long-haul trucking. We don't have to rail our oil out, we're the second largest producer in the Rocky Mountains to Connecticut, Philippe. So we have a lot of relationships and we've been doing this for a long, long time and we're good at marketing oil in this area.

So either I think that helps being up here for a while and then we don't really see big, big capacity restraint. We've seen the differentials really tightened up. Have you ever seen $5 -- $5 differential at the well. So we're real pleased with how the differentials are going out. If we could just get to NYMEX to run up would be really doing something.

Joseph Allman - JPMorgan

That's okay. And the main refinery you feed your own too (ph). Which one is that?

Jon Brumley

We've feed them to. We take this oil. This oil can go to a lot of different prices and I sure wouldn't want to talk about our marketing arrangement in the Bakken on a conference call.

Joseph Allman - JPMorgan

Okay. Understood. Okay. And then lastly, in terms of over to Cedar Creek Anticline. Any update on the sourcing of CO2?

Jon Brumley

We just keep Bakken. I mean, that is progressing, but that's a competitive area too and again, I wouldn't want to talk about negotiations especially when you completing on a conference call or either.

Joseph Allman - JPMorgan

Okay, I appreciate that. Thanks, very helpful.

Operator

Thank you. Your next question come from the line of John Freeman with Raymond James. Please state your question.

John Freeman - Raymond James & Associates

Hi, everybody. Good quarter.

Jon Brumley

Thanks John,

John Freeman - Raymond James & Associates

First questions on the Bakken just based on kind of what can your core prospect -- and then the results are seem so far Charlson. It would appear like a lot of other operator is near your area that you're continually getting better results in the Sanish then the Middle Bakken, just kind of what your thoughts are going forward. Do you start to focus more-on-more on the Sanish and then when do you think we would possibly get additional information on whether the Sanish is a completely separate reservoir is not communicating with the Middle Bakken.

L. Ben Nivens, Jr.

This is Ben. As far as the Sanish over the Bakken and it depends on the area, the Charlson area has been drilled in the Sanish, from the start, but there is some promising Bakken wells in the Charlson area as well. The Cherry area we have one Bakken and several Sanish wells. But the Bakken well is as good as any of our Sanish well.

So I think we have potential for Bakken and Sanish in the Cherry area. We will continue to drill for the Sanish in the Charlson area this year but, we see the Bakken as an attractive target.

So I think that kind of answers the second part to your question about you know, what we feel as far as whether they're connected or not, the jury is still out on that. As we said before there is probably areas in which they are an areas in which they are not.

L. Ben Nivens, Jr.

But its pretty exciting because the Bakken. There is one operator in Charlson that concentrates on the Bakken, and they get really the same size as well as we're getting. So I think there could be an opportunity that we double up in these areas and we get both the Bakken and the Sanish in both Cherry and Charlson. And we're going to do some testing on that. Probably more in 2010 as our cash flow increases.

John Freeman - Raymond James & Associates

Okay. Yes that's kind of what I was alluding to as when you might plan on doing a test to know I guess more definitively. Staying on the Bakken are there any pod locations that are in Almond?

Jon Brumley

No.

John Freeman - Raymond James & Associates

No. And then moving on to the Haynesville was there any difference in the way that the non-operated Haynesville well has completed relative to your operator well that was drilled in the same area?

L. Ben Nivens, Jr.

This is Ben again, there really was not. There were pretty much the same completion, we had non-stages I believe they had 10 or 11. And we thought with those guys a lot. So, we're -- we have a lot of direct contact with them as far as drilling in the completion on those wells. So, they're very, very similar.

John Freeman - Raymond James & Associates

Okay. And then just a last question, I'll turn it over to somebody else. The two wells that were cited in the West Texas JV, the Macro and the Brown Bassett, they both had net revenue interest that were higher than normal. Is there anything I should read into that in terms of like Exxon not participating in all the wells or am I just missing something?

L. Ben Nivens, Jr.

That's correct. In the sort of 2007 and already 2008 Exxon did elect not to participate. They are beginning to participate more in the wells but you're correct. Those high net revenues interest are the results of them not participating in those particular wells.

John Freeman - Raymond James & Associates

Great. Thanks again. Good quarter.

L. Ben Nivens, Jr.

Thank you.

Operator

Thank you. Your next question comes from the line of Scott Wilmer (ph) with Simmons & Company. Please state your question.

Unidentified Analyst

Yes. Question on your Haynesville, you are delaying completion at what price does it become attractive to complete that well?

Robert Reeves

Oh I mean, it go at probably 5 or 6 bucks you'd really I mean you might make a hell lot more money, $6 you may twice as much revenue than you do in it $3. So yes, we price start banging about at $5.

Unidentified Analyst

Okay, and what does current wells cost than in the play for you guys and what kind of decreases have you guys seen in completion cost?

L. Ben Nivens, Jr.

This is Ben, our current well cost are around $10 million headed to $9 million drilling and completion, one of the big drivers and that is the cost of stimulation. Some of our current bids are 50 to 60% discounts over what we saw on the fourth quarter of '08, so that's really driving cost there.

Unidentified Analyst

Okay, are you guys -- what type of profit are you guys using there?

Jon Brumley

It's a high (ph) I forget exactly the brand name forward.

Unidentified Analyst

Okay, and then just looking at well cost in the Bakken obviously you guys have done a 4.2 million with the goal of getting down to 4. Where do you expect to see those savings come from and is there a chance that you get below 4 million?

L. Ben Nivens, Jr.

Yes. That is -- this is Ben again that's on a 640 without a liner single stage frac a lot of those cost are coming from the stimulation part of it, similar discounts as we were discussing on the Haynesville, we're seeing 50% to 60% discount over just a few months ago on the directional I mean on the stimulation on the rest of the drilling side you are seeing savings across the board, rig rates are coming down bit, the cement, the rent is everything is down 20 to 25%. And we could we believe we'll continue to see some cost reductions.

Unidentified Analyst

Hey, great that's all I have, thanks.

L. Ben Nivens, Jr.

Thanks Scott.

Operator

Thank you. Your next question comes from the line of Chris Pikul with Morgan Keegan. Please state your question.

Chris Pikul - Morgan Keegan

Yes good morning. Could you just add a little color on the west Texas wells, it seems like you've drilled quite a few out there but was there anything on the drilling or completion side that resulted in these having lower than anticipated decline?

L. Ben Nivens, Jr.

This is Ben again. I'll start with the -- well, that was, we actually believe we hit a better part of the reservoir than we anticipated as we went as we were trying to extend it to the north a little bit, the northern and the east.

And we're offsetting that well and we're starting to test that well and are kind of excited about that offset as well. The Brown Bassett well that's a large drawn field and you just have some variability from well to well. This turns out to be a strong well field in the initial rate and the decline rate.

Its just identical -- being a large reservoir you just see a little variability in the rock from place to place.

Robert Reeves

But we are finding out more and more about these areas and getting better at drilling at and probably the results are just bigger. We did a good, projecting the IPs relatively close to actuals the reserves, why can't it be a little bit better. So its really looking up.

Chris Pikul - Morgan Keegan

Can you remind me the comparison you made to the Haynesville, did you say more IP rate per well cost?

Robert Reeves

Yes per capital dollar spent. Its just a higher rate of return. The $5 gas is a Haynesville is about a 15% rate of return and for these are run at 17 to 18% rate of return.

Chris Pikul - Morgan Keegan

Yes, it is pretty impressive. Are you seeing anything in your well result either on the successful side or otherwise it makes you want to re-shift or reallocate your budget or change your spending this year, you are pretty much standing in part with your original strategy?

Robert Reeves

We're staying in path with the original strategy. It just makes so much money. And so with your with improving the balance sheet really strengthening out the company in a year like 2009, I think this is really a good strategy and right now prices are really low and it does not make sense to burn these projects ups.

Chris Pikul - Morgan Keegan

So assuming if you get more active or at least complete the wells in Haynesville in 5 or 6 bucks are you -- is there an oil price where you start to think about increasing activity in the Bakken or anywhere else?

Robert Reeves

I think the first thing is that we get this $190 million of debt pay down, make sure that we have a good plan for that. And so I think that as cash -- prices were to increase we'd have more cash flow to drill with. And so that's when it will happen.

Chris Pikul - Morgan Keegan

Well, that was an impressive quarter. Thanks guys.

Robert Reeves

Thank you.

Operator

Thank you. Your next question comes from the line of Steve Berman with Pritchard Capital Partners. Please state your question.

Steve Berman - Pritchard Capital Partners

Good morning everybody.

Jon Brumley

Good morning, Steve.

Steve Berman - Pritchard Capital Partners

The 4.2 million, just want a clarification the well cost on the Sanish well, is that the cost of the upcoming wells or was that the cost of those wells?

Robert Reeves

That's the cost of the current Charlson well that we are projecting. We just TD that well, we haven't completed it yet but looking forward we think we're going to be able to do that for about 4.2 million.

Steve Berman - Pritchard Capital Partners

So the three successful wells course, about what?

Robert Reeves

They were closer they were at well, they are a mixture of 12 80's and 6 40's. So they vary from about a little lower over six to around five.

Jon Brumley

All right and just looking at the slide from your Analyst Day presentation on the economics, I mean these wells economic at this kind of oil price, so as cost and differentials you're seeing?

Jon Brumley

As you approach five, you started approaching them closer to a 15% rate of return at these prices and with these tighter differentials.

Steve Berman - Pritchard Capital Partners

These 250,000 barrel kind of rate of return these type of wells these 500, 450, 500 BOE they are wells but they've sitting into that?

Jon Brumley

Yes the Charlson wells bigger than that, the Cherry wells are about that.

Steve Berman - Pritchard Capital Partners

Okay. And I get going down to the Haynesville the whole well, can you give us total cost on that one specifically?

L. Ben Nivens, Jr.

That we have it has a non-operated well. There are problems drilling that I'll bet you that well costs either anywhere 13 to $14 million. So, it was but going forward we think we can drill them for 8.6 million. There was just, yeah, it was just that operators first well in the Haynesville like many other that had trouble drilling it. Now I'll say this that the Dunn well that we have set pipe on but waiting on completion. We drilled that about as fast as we drilled that Corby's (ph) well which is in the top 30%, so we're really doing a good job at getting our wells down fast.

Steve Berman - Pritchard Capital Partners

How many day Jonny was that?

Jon Brumley

I can't remember. But it's in the top 30% of wells drilled in the Haynesville. The only operator that beat us was Chesapeake. They had all the fast one. We're really doing a good job.

Steve Berman - Pritchard Capital Partners

Was the 8.6 million an actually AFE you got on the two non-op wells that are currently drilling?

Jon Brumley

No. If we were to drill a well right now, an operated well. Spread an operated well in the Haynesville which we've not. We're drilling in the Cotton Valley line or for the Bossier. It would be $8.6 million AFE.

Steve Berman - Pritchard Capital Partners

And one last question. The Caspiana field it seems to be more in the middle, more sort of in the sweet spot and then perhaps the Greenwood Waskom, is that a fair statement or is it just too early to really come to that kind of conclusion?

Jon Brumley

It might be a little bit early but I do think there's some truth to that statement. I mean we're expecting 10 to 15 million a day average range at a Caspiana and probably expecting around 7 million a day to up to 10 million a day for the Greenwood Waskom area. So, I think that Caspiana was probably is a little bit better.

Steve Berman - Pritchard Capital Partners

And then anything on the horizon for any non-op for in the own growth anything there?

L. Ben Nivens, Jr.

Yes, this is Ben. We expect a well to be drilled on our acreage in the third quarter in Ambrose and its for the Haynesville.

Steve Berman - Pritchard Capital Partners

Great. All right, thank you guys.

Operator

Thank you. Your next question comes from the line of Noel Parks with Ladenburg Thalmann. Please state your question.

Jon Brumley

Hey, Noel how are you today?

Noel Parks - Ladenburg Thalmann

Good, thanks how are you?

Jon Brumley

Good.

Noel Parks - Ladenburg Thalmann

I had few things, want to jump over to West Texas again for a second. And I am sorry if I miss this from this or prior call. Did you like haven't drilled to offset to that pile well that you had done last year?

Jon Brumley

Yes, and the drilling went well on that one. We are currently going to complete that well sometime in the second quarter. That should be mid to late second quarter well.

Noel Parks - Ladenburg Thalmann

And I mean, what you see from logs and so forth, basically meet your expectations or?

Jon Brumley

Yes. It did.

Noel Parks - Ladenburg Thalmann

Okay, great. Over on the Bakken, I thought I heard a statement that you were considering Charlson to be your best area overall out of the different pace of the acreage. So you take Charlson is looking even better then what you've done Murphy Creek (ph) for the most part?

Jon Brumley

Yeah. Probably a little bit better. It just seems to the wells really hang in. They have good IPs and they've really stayed flat I mean it's a first class area. So we're real proud on that Charlson. I mean Murphy Creek is good and we like it but the Charlson area is a little bit better.

Noel Parks - Ladenburg Thalmann

Okay. Is the difference on matter of I don't know pressures or just nature of the statistics of the targets or...

Jon Brumley

That's really the difference, it's a reservoir difference.

Noel Parks - Ladenburg Thalmann

Okay. And again asking about Almond, and you touched on this a little bit. Almond Bakken was large, I mean how uniform is the geology across that acreage, I mean do you feel pretty confident and you're likely to see somewhat different results that you think go to the opposite corner of your acreage or do you have any sense of that one way or the other?

Jon Brumley

Yeah, I mean we like the Almond acreage that's why we leased it. I think there could be a chance, but I mean after drilling that -- whole it is a little bit more difficult. I do think it is a big log. But it is pretty -- I am just -- it is riskier now.

Noel Parks - Ladenburg Thalmann

Okay, fair enough. And I think that's most of what I had. Maybe just one housekeeping question. So normally going into the rest of the year still looking for the CapEx at about 310 million?

Jon Brumley

Yes, we're going to do is protect a 190 million in CapEx will whatever cash flow is.

Noel Parks - Ladenburg Thalmann

Okay, and as we look ahead, I know its early but if you look at how to little bit to what 2010 might look like I'm sure you're thinking of sort of best case and worst case scenario going forward. What kind of -- what project to serve your biggest swing project thus far as where you get the most bank for the buck, you had a little but more capital to think into it. Would you prefer to be the Haynesville, the Bakken or just depend on solely on prices.

Jon Brumley

I mean the Haynesville in the West Texas JV are really good. And the Bakken is IPs and AURs are as good as the Haynesville or the West Texas JV on a 6:1 basis.

But when you compare that it's oil on a 15:1 basis, it starts -- it's a whole new ball game. And so I think it all depends on the oil to gas ratio and where prices are. Right now drilling for gas, and completing gas is difficult because the price is so low and oil, this has the better margin. That's why we're so lucky to have these flat oil properties that the company and that's why our company is holding up so much better than our peers. It's because of our barge oil component. That's why when we buy properties we easily concentrate on buying oil, but we have drill gas because that's where the drill gas because that's where the opportunity is.

Noel Parks - Ladenburg Thalmann

Okay. And then John one last one looking at the strip in 2010 for oil looks like its been hanging in pretty in low 60s is that a bit enough price, you're starting thinking seriously about some more hedging into 2010?

Jon Brumley

We have 40% hedge in 2010. We hedge at the beginning at 2010 at around to 60ish number and then we're awaiting for OpEx cuts to take hold and the aftermarket excited and before they took hold so we hedged another 20% at 65. And then are waiting for the driving season, historically think we'll be able to give another increase in price and we'll be settle in 2010 for another 20% then and so then will be 60% hedge for 2010.

Noel Parks - Ladenburg Thalmann

Great. Thanks a lot.

Jon Brumley

Thank you.

Operator

Thank you. We have time for one more question. Our final question comes from Kevin Smith with Raymond James. Please state your question.

Kevin Smith - Raymond James & Associates

Hi, good morning gentlemen. I had a question on Encore Energy Partners. I'm just looking at the oil realized price and see if you guys can warm up me through that. Did you monetize any hedges for the quarter?

Robert Reeves

No. no that's just the net oil price for the quarter.

Kevin Smith - Raymond James & Associates

Okay. I was just trying to match up with I guess, your hedging revenue from oils you had 3,130 BOE/D that you hedged it 110 that contract alone. I guess that was coming up with -- little bit higher than what your oil prices was for the quarter but -- am I looking at it incorrectly?

Robert Reeves

Yeah. Because the hedges did not flow through our oil revenues.

Kevin Smith - Raymond James & Associates

Okay. So those are...

Jon Brumley

Hedges flow through the derivative fair value line

Robert Reeves

Is that netted that against the future non-cash to flow that line?

Robert Reeves

Future non-cash yes.

Kevin Smith - Raymond James & Associates

Okay. So that's a net number of your realize derivatives in your mark-to-market derivatives. That's fair?

Robert Reeves

That's exactly what it is and we breakout in the reconciliation of that you can see how much was cash associated with the quarter for hedges which was right at 24 million.

Robert Reeves

Okay.

Jon Brumley

So but the oil prices is just a better oil price for the quarter.

Kevin Smith - Raymond James & Associates

That makes sense. So the top-line just doesn't have any of your realize hedging impact.

Robert Reeves

That's correct.

Kevin Smith - Raymond James & Associates

Okay. That completely clarifies for me. Thank you very much.

Robert Reeves

Okay. Thank you.

Operator

Thank you. This concludes today's question-and-answer session, I will now turn the call back over to Mr. Jonny Brumley for his concluding remarks.

Jon Brumley

Well thanks for being on our call. I don't think we could be proud of this quarter. We really did a good job on the production, I'm real proud of the operating drove. I like our bond deal does like the company much more comfortable. And then also we're really excited about this plan unlike the debt pay down, like improving the company. And pleased with how 2009 shapen up and appreciate you be in on the call and give us a share if you have any more questions. Thanks.

Operator

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

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Source: Encore Q1 2009 Earnings Call Transcript
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