Encore Acquisition Company, Q4 2007 Earnings Call Transcript

Feb.15.08 | About: Erickson Air-Crane (EAC)

Encore Acquisition Co. (NASDAQ:EAC)

Q4 2007 Earnings Call

February 15, 2008 1:00 pm ET

Executives

Jonny Brumley - President, Chief Executive Officer

Diane Weaver - Investor Relations

Phil Devlin - Senior Vice President, General Counsel, Secretary

John Arms - Senior Vice President Acquisitions

Ben Nivens - Chief Operating Officer, Senior Vice President

Bob Reeves - Chief Financial Officer

Jon Brumley - Chairman of the Board

Kevin Treadway - Vice President, Land Group

Analysts

Brian Singer - Goldman Sachs & Company

Pavel Molchanov - Raymond James

Joe Allman - J.P. Morgan

Scott Wilmith - Simmons & Company

Noel Parks - Ladenburg Thalmann

Operator

Good afternoon. 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. (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 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, President and CEO. Thank you. Mr. Brumley, you may begin your conference.

Jonny Brumley – President, Chief Executive Officer

Thanks for being on the call. In the room with me today is Diane Weaver, Phil Devlin, John Arms, Ben Nivens is here, he is our Chief Operating Officer and will be able to answer technical questions, Bob Reeves; our CFO, and then Jon Brumley our Chairman and then Kevin Treadway is in the room too, he heads up our Land Group.

I will be going over the Encore Acquisition Company part of the call and then I am going to turn it over to Bob Reeves. Bob is our CFO and he will discuss the Encore Energy Partners part of the call.

I think it will be easier to follow when you hear the change of voice and just make it more clear what entity we are talking about. So I will talk about Encore Acquisition Company and Bob will talk about Encore Energy Partners.

I would like to start off saying, we are happy with how 2007 turned out. We refocused the company back to Rocky Mountain oil and that’s paid off. When we purchased our Big Horn Basin and Williston Basin acquisitions back in early 2000 oil is in the high 50s. We purchased a great set of assets. We have seen the assets performed from a technical standpoint and from a production and reserve standpoint. And then also really preform well, because the price as you know, as oil price in the mid 90s.

To de-lever the company, we sold $300 million of Deep Anadarko Basin gas production and then further de-levered with our MLP. The plan worked and you could see that in the 2007 results.

EBITDAX for 2007 was 476 million and was a whopping 151 million for the fourth quarter of 2007. Production grew by 20%. Production was 30,807 barrels of oil equivalent per day in ’06, and 37,094 barrels of oil equivalent per day in ’07. The fourth quarter of 2007 production was 37,530 barrels of oil equivalent per day, and that beats the mid-point by about a thousand barrels a day.

Clean EPS for the fourth quarter beat guidance. The clean EPS was $0.70 per share and estimates were $0.61 per share. All in all, it was a great quarter. We were over budget on production, over budget on revenues, and right on budget on lease operating expenses.

And we put together a great budget for 2008. In ’08, we expect to grow production about 6 to 8% with a $445 million capital budget. And on top of that, we expect to repurchase $50 million of stock. We’ve already repurchased 25 million. So, it feels good to be here in February and be halfway done with our $50 million repurchase plan.

The average price for the first 25 million was $32.01 per share, and we think our stock is under valued. We are putting our money where our mouth is. We’ve seen big discretionary cash flow growth. In 2006, our discretionary cash flow was $5.19 per share. In 2007, discretionary cash flow per share was $7.17, and we are expecting $9.70 per share of discretionary cash flow in 2008. And that’s a lot of growth, and I don’t think the market is aware of that. So, we are using that to our advantage with our repurchase program.

Encore’s inventory is strong. I feel real comfortable with our projects. They are high return and low risk. In reviewing our inventory, it is clear that we can maintain this level of CapEx expenditures through 2011 and not increase our risk profile. So, with Encore, what you have is a company with a growing inventory, a growing resource base, and you have a company that with a shrinking share count, and I believe that’s going to lead to increased equity value.

In ’07, we began developing two new plays in North Dakota, the Bakken horizontal play and the Madison play. Our first Madison well came on for 700 barrels per day gross and about 385 barrels per day net. We just spudded an offset to that well on February 10, and we have about 50 additional Madison locations. That well only cost $3.1 million to drill and complete. So, obviously with IPs like that and with that low capital costs, that’s a very, very high rate of return project. And you will see a lot more of the Madison in 2009. Our Bakken and Madison teams have really been doing a good job and I am proud of the opportunities that they are finding.

We completed three Bakken wells during the quarter. The average for a 7 days IP was about 450 barrels a day for those three wells, and our drilling and completion costs got better. We dropped it below $4 million to 3.9 million. That’s really good. I think that’s probably the lowest in the play, lowest CapEx per well.

We are beginning to experiment with different types of completion techniques, so we are happy with what we have. But, at Encore, we are always trying to improve. We will move from 1 rig to 2 rigs in the Bakken by May ’08, and we were able to add the second rig because we have done a good job taking our play in. When we bought the Williston Basin acquisition that came with 38,000 Bakken acres. Right now, we are up to about 140,000 net acres in the Bakken and we will continue our leasing program, and make this play larger and larger, and this will also like the Madison be a bigger part in 2009. But, when you layer the two new Madison and Bakken plays on top of our ’06 inventory in New Mexico, East Texas, and the West Texas JV, you really do get a good healthy growth company.

Now, we will talk about the West Texas JV. The West Texas joint venture with Exxon Mobil is moving forward at a good pace. We started the year off in ’07 at 700 barrels of oil equivalent per day, and we finished the year at 2000 barrels of oil equivalent per day. We are 75% complete with our commitment wells. Those are the riskier wells in the play. So, it’s good to get those behind us, and that’s going to lead to a lower risk/higher return development program.

In midyear, we completed our obligation phase. So, we don’t have any commitment wells in the second half of the year and that’s really going to help out getting those wells, those riskier wells, behind us, it’s working, but it’s only going to work better.

We also expect rig rates in the JV to drop. We think they could drop by as much as 20% as long-term contracts expire and this will happen around midyear too. So, the combination of less expensive lower risk wells and lower cost, capital cost, for the wells is going to lead to a better program.

Another exciting part is completing the obligation phase as we were able to test more formations that we drilled through. In the Delaware Basin, we will have earned the right to develop many of the shallow zones, such as the Permian, (Sprayberry), Wolfcamp and Pennsylvanian sands, and many of these are productive and areas around our field, but they were not fully developed by Mobil.

In the Wiltshire Field, we are also encouraged with the Wolfcamp and the Barnett Shale and so we are excited about testing these formations. We budgeted 29 wells for the ExxonMobil JV and have an additional 180 locations. So, we’ve got a lot of running and rip in this and it keeps getting better and better. We are drilling the wells cheaper.

At the beginning, we were drilling the wells at around, it took about 289 days to get them on production and we’ve dropped that to 85 days. So, our drilling department has done a good job and we are really proud of the work that they have done.

Now, elsewhere in West Texas, we added (perks) to a well in our Sand Hills field in the fourth quarter, and that well came on at 300 barrels a day, and we have included three offset wells to that in 2008. So, we are excited about that too.

Our New Mexico team has been doing a good job of growing its inventory. We recently struck a deal with ExxonMobil in Lee County and this lease grows our potential locations from 25 to 45 locations. So, there’s a lot to do on this lease, and we are excited about it.

We plan on drilling 12 wells in New Mexico, and then participating in four non-operating wells. So, 12 operated and 4 non-operated. In New Mexico, that started the year off in January of ’07 at 400 barrels of oil per day equivalent. And this is really a gas area but since we are an oil company, we speak in BOEs, and that grew to 1400 barrel of oil equivalents per day throughout the year. So, we have seen a lot of good success in New Mexico in 2007.

On our rate of return look back which we do for every area, New Mexico has generated a 168% rate of return since late 2006. So, with these kinds of results, it’s great to see this area growing.

I think when investors look at Encore, and I hope they are seeing this that the inventory is bigger and better than they previously thought. Our team has worked hard to build the inventory, it’s low risk and now we are developing it.

I think one thing that is very important when you look at us is the quality of the asset base in the production, and that’s why we are able to grow with $445 million, and that’s only 75% of our budgeted EBITDAX for 2008. And you could not generate this type of results if you didn’t have a top notch shallow declining asset base. And we have a lot of good water foot in tertiary projects that flatten the decline on our base and allow us to grow with much less than cash flow. And then we will have free cash flow left over and we are going to use that to repurchase shares.

Our share repurchase programs, will reduce shares by about 3%. So, when you add the 6 to 8% of production growth and account for the 3% of reduced shares from the $50 million stock buyback, we are growing production at about 9 to 11% per share, all within discretionary cash flow. That’s a good growth rate especially because it is inside the discretionary cash flow.

I will summarize the EAC portion of the call, with 2007 being a great year for Encore, the inventory is rejuvenated, production is on target, and we look forward to 2008. We have five exciting plays, East Texas, New Mexico, the West Texas JV, the Bakken, and the Madison, and we layer on top of that a shallow declining production base and you really do get a good company.

I would like to point out that we have a new investor presentation on our website. I encourage you all to go to that and look at it, and I think it does a good job of describing the company. We have an analyst conference call, I mean, Analyst day, March 4 in New York, and so I think that will be exciting. I’m really happy about that opportunity to get to describe to the investment community all of the good things that are going on at Encore.

And now I’ll turn it over to Bob Reeves, and he can discuss Encore Energy Partners.

Bob Reeves - Chief Financial Officer

Okay, thanks, Jonny. I’d like to start out by stating that we do plan to recommend to the ENP Board a new distribution for the first quarter of 2008 of a $1.73 per unit. This equates to a 12% increase there with a fourth quarter distribution rate of a $1.55 per unit, and a 24% increase over the IPO distribution rate. At yesterday’s close, this equates to about a 8.76% annual yield and we expect the distributions to be over 90% tax sheltered for the next three years. So, with interest rates headed down it’s hard to be an 8.76% annual return that is virtually tax free.

We set the distributions on the partnership at a conservative level to ensure we can maintain the long-term distribution rate. We’ve tried to manage these distribution risks by putting first class properties into the partnership that have a shallow decline with drilling and enhancement opportunities to keep the production flat. We think, we can keep our current asset base flat for many years.

In the MLP, we favor oil rating over natural gas because of the high margins shallow decline and reservoir opportunities that characterize oil properties. When you have a shallow declining base and high margins, it allows you to have low maintenance CapEx budget. After the drop-down, our properties will allow us to maintain production over the long-term for 13.7 million per year or 3.4 million per quarter, which is about 15% of our projected EBITDA.

For 2008, we only plan to invest 10 to 11 million, which leaves us a CapEx cushion of 3 to 4 million in 2008 and this is reserved for future periods. The maintenance CapEx for the first quarter of 2008 is expected to be 4 to $5 million and then taper off to about 2 million per quarter for the rest of the year. I think, it’s important to point out that we plan to keep production flat over 12-month period than flat from quarter-to-quarter and it’s the same thing on the capital side, so you are going to see fluctuations in the capital and fluctuations in the production from quarter-to-quarter but over a 12-month period it’s going to be very constant.

We continue to execute our hedging program of protecting the distributions against downside commodity risk while leaving the investor exposed to upside potential from higher commodity prices. We are currently hedged through 2011. We can maintain our new distribution rate of $1.73 per unit through 2011 with a coverage ratio of at least 1.1 time as prices as low as $40 oil and $4 gas. So we feel very good about our hedged position in relation to protecting our distributions.

It cannot be stressed enough how much of a difference it makes to have a strong C-corp sponsor like EAC. It allows the partnership to continue to make acquisitions of first class properties as you could see in this most recent drop down that we just completed. It also demonstrates just how committed the C-corp is to MLP with EAC taking back 50% of the purchase price in units in the last deal. We are running this partnership for the long-term and a strong corporate parent is a central part of this equation.

When you look at the first class of properties that we started this MLP with and then the properties that we just recently dropped in, the low maintenance CapEx requirements and the high margins that we are getting from oil, we have the hedging program and the strong upstream C-corp sponsor. We have a lot of comfort in our ability to maintain these cash distributions over the long run.

Now, I would kind of like to walk you through the components, the reconciled distributable cash flow and talk a little bit about each component. For the fourth quarter, we had average NYMEX price of $90.92. Our differential was $25.26 or 28%. This led to a well head price of $65.66. We expect our oil differentials to vary from quarter-to-quarter with the highest differentials expected in the first and fourth quarters of each year with the average of about 23% for this set of properties per year and then on the post drop down basis, it would be about 18% differential on our oil. We are expecting 19% differential in the first quarter of 2008. Therefore the fourth quarter our oil revenues totaled 20.3 million.

On the gas side, the NYMEX gas price was average $6.97 for the quarter. We actually had a positive differential in the quarter, $0.22 which gave us a well head gas price of $7.19. And the gas differential was positive in the quarter because the (rock) accounted gas is rich. We are forecasting a negative 11% differential for gas in the first quarter of 2008 and we are just calculating that on a dry gas basis. So, when you factor in with liquids, it will probably be a little bit higher than that.

So, in total our gas revenues were 3.5 million for the quarter. We had marketing revenues of 1.6 million and there was an offsetting marketing expense of 1 million down on the expenses which netted out the marketing revenues and expenses to about 600,000. So, total revenues were 25.3 million for the quarter.

Now, I am going to move over the volume side. We averaged 4,222 BOE per day for the fourth quarter of 2007, which was slightly below our expected range, but it was not due to any operational problems or poor drilling results. In fact, production in December averaged 4,528 BOE per day and the initial first quarter 2008 results are above our expectations. In fact, the drilling program Elk basin in the frontier formation turned out just like we were thinking. We drilled nine wells. We had six of these wells on by the end of the year. We have the other three wells on in the first quarter. The 30-day average initial production rate was 45 barrels of oil per day and we drilled these wells for about 400,000 per well on the frontier formation.

Additionally, the Elk Basin field staff is just doing an excellent job on the base production out there and they are finding more ways to add productions and that’s really the great part about owning a legacy field like Elk Basin that has 1.3 billion barrels of original oil in place. You can always expect to fund more things to do to increase the production and the reserves.

Now, I would like to move over and talk a little bit about the expenses. On a cash basis, factoring in all our expenses, our total expenses were 10.9 million for the quarter, excluding non-cash items such as DD&A, hedging mark-to-market for future periods and equity-based compensation.

For LOE, it was slightly higher on a per barrel basis, but in total LOE was exactly like we are projecting and it was just a little higher on a per barrel basis because we have less production in the quarter because of the delays in the drilling and the bad weather that we’ve talked about.

G&A was higher for the fourth quarter because of expenses related to the drop down. We incurred about 500,000 of expenses associated with the drop down from EAC. We do not capitalize those costs and those costs immediately go through G&A as an expense.

And then, we had public company expenses in the fourth quarter like audit fees, K-1 preparations and printing fees that all hit in the fourth quarter of 2007, really our first quarter of being a public company and those all hit in the fourth quarter as opposed to being kind of spread out throughout the year.

So, on a go forward basis, you should expect the $1.75 per BOE to cover EAC administrative fees that we pay and then about another $0.90 per barrel for third-party public expenses like audit, printing fees, Directors fees, insurance, K-1 preparation, et cetera. So that would total about $2.60 per BOE for cash related G&A charges. Compensation expense will be 3.6 million for 2008 or an additional $1.60 per barrel that equal to our G&A.

On the interest expense side, it was lower than we expected because of the LIBOR rates that we are paying on our credit facility and we recently took advantage of the low LIBOR rates by locking in 100 million variable rate debt and moving it over to fixed for three years at a LIBOR rate of 3.06.

We think we are going to be able to get hedge accounting on these contracts. So, I would expect the settlements to flow through interest expense on the income statement in the future as opposed to flowing through derivative fair value like our oil and gas commodity contracts do.

We finished the year with $47.5 million on our revolving credit facility. Post drop down, we will have about 172.9 million of debt on the facility. Our availability on the credit facility moved to 240 million, so we will have additional debt capacity of 67.5 million post drop down. With the current distribution of a $1.73 and current prices, we should be able to payoff about 20 million on the credit facility in 2008.

For the derivative fair value loss that we had that was 16.8 million for the quarter, we did not use hedge accounting for our oil and natural gas derivatives. So, we actually had cash settlements in the quarter of right around 400,000 on our natural gas hedges. The rest of the $16.8 million charge was 15.8 million for the mark-to-market of these contracts for future periods and then 1.4 million for premium amortization. And these mark-to-markets on our hedging portfolio do not impact our ability to pay distributions in the fourth quarter or in future quarters.

On the capital side, we incurred $5.6 million of capital in the quarter, and this compares to the third quarter where we invested just $1 million. Included on the reconciliation at the back of the financials, we added back the accrued development capital of 1.6 million and added back our maintenance capital reserves of 1.8 million. Before the drop down, we said that our maintenance CapEx was 8.7 million per year or 2.2 million per quarter and that’s what we deduct to get to our distributable cash flow.

On a go forward basis, like I stated earlier, we plan to reduce cash available for distribution by 3.4 million a quarter or 13.7 million per year, regardless of how much capital we spend in the quarter and the additional amount that we reserve will be held aside for future capital expenditures beyond 2008. This gets us to cash available for distribution for the quarter of 12.3 million. We planned to distribute about 9.8 million to unit holders of record as of February 6, 2008.

For the fourth quarter that implies a coverage ratio of 1.26 times. For 2008 current prices, we expect our coverage ratio to be about 1.4 times when you factor in -- without factoring in the capital reserve and if you factor in the additional cash that we would hold for capital expenditures in the future that brings our total coverage ratio to 1.5 times.

So, with that, I’ll turn back over for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Your first question comes form the line of Brian Singer with Goldman Sachs & Company.

Brian Singer

Thanks. Good afternoon.

Jonny Brumley

Hi, Brian. How are you?

Brian Singer

I’m well, thank you. What do you see when you look at your 6 to 8% growth rate as the contribution to growth from the oil drilling side versus the gas drilling side versus the improved oil recovery side, really wanted specifically focus on improved oil recovery and how you see that playing out this year?

Jonny Brumley

Yeah. It’s about 40% oil-driven and 60% gas and of the $445 million budget, 67 million of that is improved oil recovery.

Brian Singer

And I guess from a growth perspective, should we expect your improved oil recovery production if you had to segment that out to be up this year, flat or down, and it seems like you are investing a lot more on the oil drilling side of the equation. And I’m trying to get to you as whether we are going to see disproportionate growth from oil versus from Bakken and Madison et cetera, relative to some of the creating other improved oil recovery project?

Jonny Brumley

Yeah. And I think you could weight out the capital from the IOR (Ph) presentation that’s where the growth would be driven from. I would like to point out that really our budget because that 67 million of IOR (Ph), you don’t get any growth for that in 2008w. So, you are really growing with a much lower -- basically $378 million you are getting to 6 to 8% growth.

Brian Singer

Great.

Jonny Brumley

We had a 445 minus the 65 equals 378.

Brian Singer

Good plan that we should expect the growth generated by the cash flow a couple of years ago and then that level of growth from the improved oil recovery will taper off a little bit in a couple of years?

Jonny Brumley

Yeah, we will keep doing at more and more improved oil recovery projects and we have a lot in a half or we are implementing seven improved – five or seven, I can’t remember what its exactly, but it is seven Ben said. Seven improved oil recovery projects in 2008, we have 27 engineers.

Brian Singer

Great. Shifting to the Bakken, can you talk about I think its 17 Bakken planning on drilling this year, to what extent those wells are a development versus proving up new undeveloped acres?

Jonny Brumley

Okay. Ben?

Ben Nivens

Okay. I don’t have the exact numbers on development versus what’s proving up new acres, but a big focus of our budget next year is improving up new acres. We have our Murphy Creek area that we drilled primarily in 2007. We’ll be continue drilling on that. We’ve already moved to another field, which we are drilling our second well on and then we intend to drill our first well in a couple of other fields new to us and they would be considered development areas.

Jonny Brumley

Yeah, I think at least half of them are going to be in new areas not in Murphy Creek. That was one of the big process to get a second rig was took it would allow us to prove up riskier areas and try to get more offsets up there, if we had more than one rig running because if you have one rig and well doesn’t work, it really shows up. But, if you have two rigs going that just allows you to smooth out the programs. So, that was really one of the pushes with that.

Brian Singer

Great. And you may have mentioned that’s earlier, but do you see further downward pressure on or further the ability for your CapEx well I think it about 4 million or so down to -- go down even more?

Ben Nivens

Yes. We do and that’s going to be driven primarily by getting a second rig and a third rig to come in and do some re-entry projects, the current rig we had, we inherited as part of the acquisition and we are seeing rig rates about $5000 a day below that number when we pick up these new rigs.

Brian Singer

Great. Thank you.

Jonny Brumley

And that’s not because that rig is super cheap than second rig. It’s a $5000 below what we are doing now. But our rig that we are currently using was very, very expensive. It was contracted by the previous operator in 2006 what would be a very high rate. But nonetheless, we are going to a have rig as $5000 less than that we are already the one of the cheapest or not the cheapest driller in the field and so, we are even going to get better.

Brian Singer

Thanks.

Ben Nivens

We are not going to sacrifice reserves or production, but trying to get better. If we plan out that production tech -- our completion technique to cost us a little more and gets us a little more reserves and we are going to do that. So, you are going to see a little fluctuation in our cost. But they are going to be generally downward.

Brian Singer

Thanks you.

Jonny Brumley

Thanks for the questions.

Operator

Your next question comes from the line Pavel Molchanov with Raymond James.

Pavel Molchanov

Hey, good afternoon guys. Quick question on your CapEx for the partnership, you mentioned 4 to 5 million on in Q1, it’s almost half of the full year total, can you just talk about what accounts for the timing of that?

Ben Nivens

Yeah. This is Ben Nivens. The timings -- part of the capital is non- op, that we have in the ENP and its a little harder to gauge, but in the -- it's going to be lumpy as Bob pointed out in his presentation proceeding to be year-to-year flat and where there is going to be some variations in one of our quarter. So, the non-op is not driven by us. So, we can plan or operate it around that. But we had a rig coming to drill in the Crockett this first quarter this year to drill some wells that we were excited about and we don’t want to back off those. So, we kept that program going when we dropped them down into ENP. So, in the first quarter we have one non-operate drilling in Crockett and one operated rig. And then, throughout the year, the other three quarters of the year we have some non-operated drilling that we see coming forward and then we have program to drill 4 to 6 wells in our frontier program in Elk Basin. So, that’s how -- the main reason it's lumpy in the first quarter is because we didn’t have the opportunities to drill the Crockett wells and there was already a non-operating in the field.

Pavel Molchanov

Got it. And secondly, more of a strategic question. On your drop down strategy, I think your first drop down surprised many people by the magnitude of the deal 250 million. Can you talk about going forward, how are you going to try structure in terms of the timing and the size of those transactions, to growth goal for the MLP or is it just purely opportunistic?

Jonny Brumley

Well, I think that we’ll use drop downs to smooth growth. If we were to make a large acquisition in the MLP then you might not see a drop down for even that year. But if we haven’t been successful in making acquisitions, we do need to fill in with acquisitions, we’ll certainly do that and that’s the luxury of having an MLP with a good sponsor parent. And so, we are going to use that sponsorship to help smooth the growth.

Pavel Molchanov

And is there a target that you guys are looking at for the MLP's growth, when you say smooth it out, a 10% a year or something like that?

Jonny Brumley

We like to grow faster than that. We think that we’ve done a good job of growing it now, but our plan is to double the distribution in about five years from now.

Pavel Molchanov

Okay, from current levels?

Jonny Brumley

Yes – no, well, from the IPO.

Pavel Molchanov

From the IPO. Okay. That helps very much. Thank you.

Operator

Your next question comes from the line of Joe Allman with J.P. Morgan.

Joe Allman

Hi, everybody.

Jonny Brumley

Hi. Joe.

Joe Allman

Hey, Jonny how are you?

Jonny Brumley

Good. How are you?

Joe Allman

Good. Thanks. Hey, I know you talked about some rig rates earlier and I think, I was distracted a little bit and I apologize for that. But, you were talking specifically about the Bakken there?

Jonny Brumley

Yes, that’s correct.

Joe Allman

Okay. And you were looking at rates maybe 5,000 a day lower than what you had contracted before?

Jonny Brumley

That’s right. Well, we still have one that expensive rig will be under contract, then we will also have a less expensive rig.

Joe Allman

And so these three wells at average 3.9 million a day, they were with less expensive rig or the more expensive rig?

Jonny Brumley

The more expensive.

Joe Allman

Okay. So you get to a lower cost that has been equal.

Jonny Brumley

We will be at a lower cost.

Joe Allman

Got you, got you. Okay.

Jonny Brumley

And so that's what I think that’s one thing that’s impressive with our drilling group as they are able to get generate these kind of results with an above market rig that we inherited with the Williston Basin deal.

Joe Allman

Got you. And with the more expensive rate and what's the current rate now on the cheaper rigs?

Company Representative

The more expensive….

Company Representative

Yeah, I don’t want to get into really what our rig rates are and announce that, I mean, this is a competitive play and we are drilling the wells for really -- I think, that’s one of our competitive advantages.

Joe Allman

Got you.

Ben Nivens

I would say, we talk about the more expensive rig as it being a bad rig. I mean, I want to stress, we are very happy with the performance of that rig and that’s one of the reasons why we are drilling wells the way we are, because we got a good rig and we got a good crude on that rig.

Joe Allman

Got you. And going forward, so -- you did a single lateral within a 640, I think?

Ben Nivens

That’s what we’ve been doing today.

Jonny Brumley

Yeah, that’s what we’ve been doing. I think what's need about our Encore in the Bakken play is we open this play up a lot for our company where we can – 250, 000, 300,000 barrel well makes a ton of money at Encore with our top notch drilling and completions team and other companies going to need a lot more reserves than we are, because they can’t do it for as inexpensive as we can.

Joe Allman

Okay and then, how many stage frac, that you do in those three wells?

Jonny Brumley

Those are singles.

Joe Allman

Okay, got you. And going forward, do you think you might be trying to have tweak here drilling and completions techniques there based on what you are seeing other operators do?

Jonny Brumley

Yeah. We’ve been doing that too, trying some different things in just -- we are always trying to improve, I mean that’s the most important thing as get better and better. We don’t mind spending more money on wells, if you get a better result. And we’ve been doing that Ben’s group had done a good job and we are just kind of watching and seeing if that extra cost is worth it right now it doesn’t seem like it is.

Joe Allman

Got you. And then, just in general, are you still -- could you tell us what the trends are for joining in completion cost -- as we got the rig store in the Bakken but what else in terms of drilling and completion cost?

Jonny Brumley

Okay. Ben will answer that.

Ben Nivens

We are seeing good decreases in the drilling cost as we already talked about. So far on the completion side, we are seeing its staying flat, it has -- we haven’t seen it gone – go down and that’s probably because we are in such an active phase and that’s stretched as far as resources go on the services side.

Joe Allman

Okay. And what are you seeing elsewhere outside of the Bakken here and….?

Ben Nivens

Well, in our West Texas play which is our single -- our other large play, we have a lot of rig contracts so our rig rates are staying constant there. They will get lower as the year goes on and some of these contracts go off and we get market rates on those. Our completion cost, we have not seen a large decrease in completion cost in West Texas either.

Joe Allman

Okay, very helpful, guys. Thank you.

Ben Nivens

Thanks.

Operator

Your next question comes from the line of Scott Wilmith with Simmons & Company.

Scott Wilmith

Hey, guys. Keep it up on the Bakken, just one question, I apologize, if I’ve missed this, but what locations where the three wells and what area in the Bakken were they in?

Jonny Brumley

One of them within Murphy Creek and one of them was North there.

Scott Wilmith

Okay, Bell Creek?

Jonny Brumley

Yes.

Scott Wilmith

Okay. And where do you these wells fall in to the range you guys gave a range of 250 to 350, are those within that range or…?

Jonny Brumley

Yeah, they are within that range. I think Murphy Creek would be towards the low end -- the 250-ish and we don’t know what this other one would be. But we don’t really not in their drill. I mean, we will drill wells that are less than 250, but we won’t follow them up.

Scott Wilmith

Okay. Do you guys have an estimated pay out period based on current prices?

Jonny Brumley

I don’t think we have that right here.

Scott Wilmith

Okay. Additionally, have you guys seen any downturn due to weather this year?

Ben Nivens

We have -- are you talking about on the rigs or exactly what you are talking about?

Scott Wilmith

Just really cold weather, not being able to operate in any downturn?

Ben Nivens

We are seeing downturn on completion rigs and work over rigs due to the extreme cold weather and high winds from time to time. It hasn’t been extreme -- there hasn’t been a lot of days. We’ve had a few of those; it’s a rough winter up North.

Scott Wilmith

In what areas are you guys impacted specifically?

Ben Nivens

The CCA and the Williston Basin.

Scott Wilmith

Okay. Okay, great. And then, just one more question as far as LOE guidance in first quarter, it’s going up a little bit sequentially, can you guys give a little more color on that increase?

Ben Nivens

Yeah. The increase is partially due to marking in and expected electrical rate increase on two of our largest areas of CCA and the Big Horn Basin. We are beating close to -- knowing exactly what that’s going to be, but it looks like it’s going to be pretty close it – it is definitely going to go up.

Scott Wilmith

Okay. Alright, guys. Well, thanks a lot.

Operator

(Operator Instruction). Your next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks

Good afternoon.

Jonny Brumley

Hi, Noel how are you doing?

Noel Parks

Real good, thanks. Again a few questions, could you talk a little bit more about New Mexico and I actually missed the very start of your comment on New Mexico, I don’t know if you are talking about a recent well reserve?

Jonny Brumley

Well, Noel, I was just saying we have grown from 400 to 1400 barrels of oil equivalent per day and that’s gas, you multiply that by 6 to get an Mcfed rate, but -- or a the rate of return is really high at 168% and we have big inventory growth there. We are picking up another rig in the second half of ’08, New Mexico, so we are really excited about this area. And again, this will be -- a common theme throughout this and this will be a bigger deal in 2009. Well -- and you are going to see that in Bakken, the Madison, and New Mexico and probably in East Texas, no West Texas we won’t have more than 5 rigs there.

Noel Parks

Okay.

Jonny Brumley

But 4 out of the 5 plays are going and they are all working.

Noel Parks

Okay. And so, I guess in New Mexico, can you talk a little bit about what you have seen in the most recent drilling, of course, that’s first well you had out there was unusually higher rig and is the most recent drilling looking like it’s closer to your average expectation?

Bob Reeves

Yeah, I think that the average well cost $3000 million and they are two to three bcf a well and that’s Morrow it’s a days play. The new lease has a lot of (Inaudible) potential, so we are excited about that too. And that’s oil so that will generate a higher rate of return in gas drilling which -- oil has been generating a higher rate of return for probably the past two or three years in gas.

Noel Parks

I am not familiar with the Drinkard and Blueberry. What are those – are there other wells by that have similar productions from those?

Ben Nivens

Yes. Those are two very prolific zones in the Delaware basin area.

Bob Reeves

They were just developed, the Drinkard and it’s the Blinebry. The Drinkard and Blinebry have been developed in the Permian Basin for many many years and that’s just -- those are two like kind of the old school Permian zones and this is just an underdeveloped lease and so we can go back and get this stuff that other operators have been getting over the past 20 or 30 years.

Noel Parks

Okay, great. Moving onto the share buyback, do you anticipate getting the rest of that done this quarter or do you think more of the sort of thing you like do opportunistically over the rest of the year?

Bob Reeves

Yeah. I think that we will do it more over the rest of the year.

Noel Parks

Okay. And I want to ask you a bit about Bell Creek where your-- I haven’t seen your 100% working interest therein. Can you tell us a little bit more about the polymer injections just sort of the nature of the targets and is it a fairly uniform recipe for the polymer across the field do you think?

Bob Reeves

Yeah, I’ll have Ben answer to that. The polymer injections are pretty neat and they are working well.

Noel Parks

Okay.

Ben Nivens

Yeah, Noel, those are just supplemental things that we are going to improve the waterflood that we are reactivating in Bell Creek for bringing more and more wells back on and injecting more water. And to inject that water more effectively, we are using these polymer injections in both the producers and the injectors to shutoff the zones that have the higher permeability and are what we consider the fast zones and cycling a lot of water. We try to shut those off with a polymer, so that you can get a more effective flood in the wells and the zones that have not been as effectively waterflooded. So, it’s really a supplement to waterflood rejuvenation project.

John Arms

Yeah. Let me kind of describe for the other listeners what Bell Creek is. Bell Creek is a waterflood that we purchased in 2001. It’s in the northern portion of the Powder River Basin and it’s in Southern Montana. At the beginning of ’07, the Bell Creek was raking about 350 barrels a day. We saw that with some supplemental waterflood water we get it to 700 barrels a day. It’s outperforming our expectations and we are sitting here at 1,250 barrels a day right now and are still growing and we’ve just scratched the surface on this. This is a huge old giant field. ExxonMobil used to own and operate this field and it was -- one-time this field produced 50,000 barrels a day, so that has 300 million barrels of original oil in place. So, it’s a huge oil field and we are just now getting going on it, but it keeps getting better and better. And so, it’s really exciting. This is -- it’s a great Tier 2 candidate. This is one of the things that could drive growth in Encore way into the future.

Noel Parks

And, what are the depths in the cost of -- the depths, the targets out there and the operating cost, I guess, as you add in the polymer and so forth?

Jonny Brumley

We haven’t drilled any wells out there. We are just doing all this growth through waterflood work, so that’s what so exciting. I mean just imagine if we got out there busier and really started investing a lot of capital in it. What the polymer is as you pump the polymer, the polymer is basically gunk that gunks off the reservoir and we pump polymer into the producer, pump polymer into the injector, we can time the polymer to where it is thinned, when we pump it in and then as it gets into the reservoir it sets up and becomes more – just really gunks up the reservoir. So, it goes into the high streak permeable zones where the water has been going and then it gels up in there and then all that water is pushed from that high streak zone to contact zones that contain more water that haven’t been efficiently waterflooded. So, what it is it’s a mechanism to increase the efficiency of your waterflow.

Noel Parks

Okay. I got it. And just as far as spending there this year and what you might think about next year or if you decide to (run) more capital added, what sort of levels are you talking about?

Jonny Brumley

I don’t know, we are currently engineering that right now. We would have mentioned it more on the call, but we just had so many things going on that are good, it -- we essentially talked about it last quarter, we didn’t talk about it this quarter. But thanks for bringing it up because it is an exciting project.

Noel Parks

Okay. I think that’s all from me. Thanks a lot.

Jonny Brumley

Thanks.

Operator

There are no further questions at this time. Mr. Brumley, do you have any closing remarks?

Jonny Brumley

Yeah, I would like to say we are really excited with how ’07 ended up and feel great about the 2008, 2009 and ‘10 inventory, even 2011 that we are building. We are really pleased with how everything is working out. There is one important thing that I think that when you look at Encore that a lot of people don’t understand but by production we are 70% oil and by reserves we are 80% oil, and oil is much more valuable than gas.

Now, if you were to take the $95 NYMEX oil price, for oil was about that when we started the call, and divide that by 6 that’s $15.80 in Mcf on a 6 to 1 ratio. I don’t think people, they are just now -- we are just starting to see the investment community come back around oil and they are just starting to notice that hey, these oil guys are making a whole lot more money than these gas guys. And so, that’s what's exciting. That’s why you seeing our discretionary -- one of the reasons why you are seeing our discretionary cash flow grow from the low 5s to the high 9s in just a matter of three years is because we are increasing our production, we are increasing our reserves and we are also increasing our margin. And so, that’s exciting and I think we have been very active in protecting that margin. In 2008, we bought a bunch of $85 puts entered into a little bit of swaps and collars but mostly doing that with puts that gives us a big time margin guarantee for ’08. And in 2009, we bought $80 puts, so we have a big time margin guarantee for ’09.

So, you’re seeing a company that’s growing its resource base, growing its production, its inventories getting better and better, we are getting better at exploiting it, we are improving in all areas of the company. And so, you just really have gotten a hold of a company that is improving all the way through and you are seeing that in improving margins, in improving production and improving reserves.

Thanks for being on the call and we are really excited about Encore.

Operator

This concludes today’s Encore acquisition conference call. You may now disconnect.

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