Denbury Resources, Inc. Q3 2007 Earnings Call Transcript

| About: Denbury Resources (DNR)

Denbury Resources, Inc. (NYSE:DNR)

Q3 2007 Earnings Call

November 1, 2007, 11:00 AM ET

Executives

Gareth Roberts - President and CEO

Philip M. Rykhoek - Sr. VP, CFO, Secretary and Treasurer

Robert Cornelius - Sr. VP, Operations

Ronald T. Evans - Sr. VP, Reservoir Engineering

Analysts

Noel Parks - Ladenburg Thalmann

Scott Hanold - RBC Capital Markets

Eric Hagen - Merrill Lynch

Nicholas Pope - JP Morgan

Operator

Please stand by we are about to begin. Good day, everyone, and welcome to this Denbury Resources' 2007 Third Quarter Results Conference Call. Today's conference is being recorded. The following discussion contains forward-looking statements and our actual results may differ materially from those discussed here. Additional information concerning factors such as price volatility, production forecasts, drilling results, and current market conditions that could cause such a difference can be found in our reports filed with the Securities and Exchange Commission, including our reports on Form 10-K and 10-Q.

At this time, for opening remarks and introductions, I would like to turn the conference over to Mr. Gareth Roberts, President and Chief Executive Officer of Denbury Resources Inc. Please go ahead sir.

Gareth Roberts - President and Chief Executive Officer

Thank you. Well, welcome everybody to the Denbury's third quarter 2007 earnings conference call. With me today is Phil Rykhoek, our Chief Financial Officer; Tracy Evans, Senior VP of Reservoir Engineering; and Bob Cornelius, our Senior Vice President of Operations.

Denbury had an excellent quarter with strong production growth, which allowed us to report earnings of 68 million, or $0.56 per share. We've also released for the first time our estimates for 2008 production, which once again, which is a very strong growth around 25% all organic.

Denbury, clearly continues to perform very well. And this is really... this really starts from the ground up with the hard work of our employees. They are doing an outstanding job of delivering these kinds of results. So, I want to thank them for that.

I also like to mention that we have an Analyst Meeting on the 7th and 8th of November in Jackson, Mississippi where we would go into some of the details of the forecast and details of the current floods. There are still a few slots available, so if anybody who would like to go should contact Laurie at our office.

With that, I would like to turn over to Phil to discuss the details of the quarter.

Philip M. Rykhoek - Senior Vice President, Chief Financial Officer, Secretary and Treasurer

Thank you, Gareth. As you mentioned, thanks to our record production results, we were able to handily beat First Call earnings and cash flow consensus, even with a 5.4 million mark-to-market charge to earnings relating to our derivative contracts. If you were to eliminate that charge our earnings would be about $0.03 per share higher beating First Call by approximately $0.10 per share.

And Bob is going to go over the detailed production in his operations reports, so I'll just hit the high points. Obviously, the key point is that our production continues to increase. We set a quarterly production record, and our tertiary production is still on track for a product guidance 14,750 barrels in 2007 as a projected increase of 46% over '06.

We are reaffirming that tertiary guidance and increasing our overall guidance to account for the strong production results from the Barnett Shale and we've also factored in the projected timing of the Louisiana sale.

If you recall, on the last call we increased it to 42,000 barrels a day, today we're increasing that to 425, that's up from our initial guidance of 40,700 BOEs a day. That gives us total production growth of 16% compared to '06, and this assumes that our Louisiana sale closes in early December, and that's factored in this forecast.

For 2008, we're forecasting an average production rate of 47,500 BOEs a day, that's used in the tertiary forecasted midpoint which gives us organic growth of 25%. If you exclude the production relating to Louisiana sale from the 2007 projected results. We are forecasting average production rate of 22,000 to 25,000 from tertiary in 2008, a growth rate of approximately 59%, again using that midpoint over 2007.

This midpoint is a little bit lower than the model we've had in some of our prior slideshows and the decrease was made to kind of simply fine tune our projections and we have made it a range rather an absolute number, to give ourselves low room as it can't be difficult to pinpoint exactly when and how fast we'd like to respond.

Due to the high weighted growth, any slight changes in the timing can significantly affect the annual averages.

Our revenue increased 32% between the respective third quarters about two thirds from higher production about third from higher oil prices.

We have done well in our hedges this year, we have collected over 19 million in net cash from our derivative contracts, of course, most of that is from the natural gas hedges during the first nine months of '07. However, as you know, these derivative contracts do significantly impact our earnings and to illustrate that, if you recall we expensed $35.2 million in the first quarter, we had a gain of $13.3 million in the second and this quarter we had an expense of $5.4 million, all related to mark-to-market adjustments.

That $5.4 million consists of $3 million related to our natural gas swaps which is really primarily due to the exploration, the partial exploration of the 2007 swaps and $2.4 million relates to our oil swaps which relate to our January 2006 acquisition, and which decrease in value because we increased in oil price.

In comparison, in third quarter of last year we had a $14.6 million mark-to-market gain. So, with this $5.4 million loss this quarter and $14.6 million gain in the third quarter of '06 that gives us a differential of $20 million swing in pretax income between the respective third quarters.

Obviously, you'll want to be aware of the impact of these non-cash charges and earnings on our... when making your comparisons. We also, you might note in the press release, we provide a little bit of supplemental information this time under the heading 'oil and gas derivative contracts,' where you can see the breakdown of the cash versus the non-cash relating to our derivatives for each period.

In case you missed our press release couple of weeks ago regarding Louisiana sale. We also announced which swapped most of our '08 natural gas production and the weighted average price of 791. These contracts are the only new derivative contracts since our last 10-Q or conference call.

The oil NYMEX differential are listed in the press release, but the thing you want to keep in mind regarding oil differentials is that they appear to be headed back to more normal historic levels. So, I'd suggest going forward they are likely to be in the $6 to $7 as they were in '06 or maybe even slightly worse on absolute dollar basis because of higher oil prices.

Our operating cost decreased 6% sequentially from $15 a barrel last quarter to $14 in this quarter, as higher production more than offset the higher expenses. The higher tertiary oil production also help reduce our tertiary LOE per barrel which is down 9% sequentially averaging 18.65 per barrel this quarter. That is in spite of a 10% sequential increase in the cost for CO2 due primarily to higher oil prices and a 7% sequential increase in the quantities of CO2 that we used in our operations.

If you look at our cost per barrel by Phase, Phase I came in this quarter $16.47, that's down more than a $1 per barrel from last quarter, and Phase II came in this quarter at $23.40 which is down almost $10 per barrel on a sequential basis.

Bottom-line, while these tertiary costs per barrel are high in our initial stages they do come down as production increases. To give you an example of that, our operating cost from Mallalieu, which is currently our highest volume tertiary producer, was 984 per barrel this quarter.

Shifting gears a little, let me give you a little data regarding Louisiana sale, as you'll need this information to properly forecast LOE going forward. As stated in the press release, production from Louisiana properties being sold averaged 5031 BOEs per day this quarter and that's about 85% natural gas. The LOE related to the Louisiana properties being sold, totaled approximately 3 million. Therefore, if you adjust our LOE per barrel for the properties being sold, it would have been approximately 1505 per barrel rather than the reported 1410.

Fourth quarter '07 will include the production and expenses related to these properties for at least October and November, so it won't impact fourth quarter too much. However, early in 2008 our LOE per barrel run probably a $1 higher than this quarter as a result of this sale.

So, therefore, even though we are gaining some efficiencies as production increases, I would expect fourth quarter to be a little higher than this quarter but still between 14 and 15. Early in '08, we will probably exceed 15 a barrel as we... and may even a little higher than that as we hope to significantly increase some of our CO2 injections, particularly at Tinsley when that pipeline is completed.

Our goal would be that with the anticipated growth in production by the end of last half of '08, we can bring LOE back down in the 14s. G&A came in pretty much as expected on a gross basis, it is about flat sequentially but lower on a per BOE basis with the higher production. In general and administrative costs are gradually increasing as we continue to see inflationary pressure in our industry, when it comes to obtaining and retaining qualified experienced personnel.

Further, we continue to grow, we increased our employee count 30% in '06, and we have increased it 12% in the first nine months. Looking forward, I think we will generally be around $3 a barrel perhaps in the mid-threes early in '08, as the impact of the Louisiana sale will increase our cost per barrel as there will be little or no G&A savings from that sale.

We continue to borrow funds for acquisitions and capital spending in excess of cash flow, raising our debt levels and correspondingly our interest. Our average debt level this quarter is 13% higher sequentially and 63% higher than the third quarter of '06. Partially offsetting the higher gross costs is a significant level of interest capitalization, primarily related to the unevaluated properties we acquired during the last two years. The interest capitalization totaled $5.4 million this quarter. Currently we have $765 in total debt, which consists of $525 million of sub-debt and 240 of bank debt drawn on our $500 million borrowing basis. As we stated in the press release, we are working on the terms of a dropdown of our two existing CO2 pipelines with Genesis and we still expect that to close before yearend.

These dropdowns would likely be a combination of property sales with associated transportation and service agreements and direct financial leases and should provide us with $200 million to $250 million of capital. It seem when we close those drop downs coupled with the anticipated proceeds from our Louisiana property sale, we should in the year, with no bank debt and between $125 million and $175 million of incremental cash.

Of course, keep in mind that while we think we are getting close to the final terms on the Genesis dropdown, it's still subject to negotiations of the definitive agreements approved by Board fairness opinion and so forth.

As we have discussed before, we will likely account for both of these dropdowns as capital releases for accounting purposes. Although we did book minor incremental reserves this quarter with the incremental future development cost associated with the additions and other capital spending, DD&A rate increased 4% sequentially to 1143.

As we have discussed before, 2007 was a bit of a transition year for us with regard to booking reserves in our tertiary program, and we expect 2008 to be a much bigger year in terms of tertiary reserve adds.

Lastly, with regard to income taxes, our effective tax rate this quarter remained at 39% and the current taxes as the percentage of the total provision represented 12%. For the remainder of the year, based on the current prices, I'd expect the total tax rate to remain the same around 39% and cash return on current tax is between 10% and 20% of that total. However, you should note, in addition, during the fourth quarter, assuming that our Louisiana sale closes and our dropdown of Genesis occurs, we would expect to pay between $20 million and $25 million of incremental income taxes relating to those two transactions.

And with that I will turn it back to Gareth.

Gareth Roberts - President and Chief Executive Officer

Well, thanks, Phil. I would like to ask, Bob, to give us a operations update.

Robert Cornelius - Senior Vice President, Operations

Okay. Thank you, Gareth. I will give you a quick operational update on several of our major projects, but first I would like to touch on again the third quarter production rates.

As Phil pointed out, Denbury entered the third quarter with an average production rate of 45,720 BOEs per day and that's a 9% increase over the second quarter. And this makes the third consecutive quarter with significant production increases.

Again, enhanced oil projects in the Barnett Shale continue to drive these quarter-to-quarter increases. Barnett Shale production on an quarter equivalent basis increased approximately 1,694 BOEs or 20% on the second quarter while the CO2 enhanced oil projects showed an increase of 2418 net BOEs or 18% increase over the second quarter. We forecasted future production increases for all the CO2 projects with the exception of Little Creek for the remainder of the year.

I would also like to quickly run through a list of the major CO2 projects with there current rates and discuss several of the operational improvements and future plans for these projects. The majority of the tertiary oil increases are from Phase II projects that's Eucutta, Martinville and Soso.

We will begin with the largest of these Phase II fields and that's Eucutta. And since first production began only 12 months ago, that was in November of 2006, the project has increased to an average rate of 2035 net BOEs per day, and that was during the third quarter. Now presently, Eucutta, it injects approximately 120 million cubic feet a day into 32 unit wells.

The team over the quarter drilled three wells and they reworked 16 of the existing wells, we added two new test stations and those are being commissioned in the Eucutta field. And these activity should be the catalyst for improving production rates into 2008.

Soso and Martinville are the two other Phase II enhanced projects, they are also performing above forecast this year. Soso averaged 370 net barrels during the second quarter and continues to increase nicely over this last quarter to a rate of 842 net BOEs, during the third quarter that's 128% increase quarter-to-quarter. In Soso field, we continue to rework the existing wells and plan to increase CO2 injection rates before yearend, and that should also add to the production rate.

With past reservoir performance and current injection to production withdrawal rates, those things indicate Soso field would continue to perform as forecasted into 2008.

During the third quarter Martinville also averaged 1,100 barrels a day, that was over a 100% increase. We do not expect the rates at Martinville to increase significantly next year. However, those average daily rates are expected to increase throughout 2008.

Moving to Phase I, of the four major projects in Phase I, Brookhaven exhibited the greatest growth. Brookhaven exhibited nice 37% production increase when compared second quarter to third quarter 2007.

The third quarter averaged 2452 net BOEs. The team there improved CO2 injection profiles into the wells. We increased the CO2 injection rates, plus the drilling all credited to improving those rates. Adding another production test sites plus four additional wells in August, those activities are going to push our production above 2,900 net BOEs, so.

Mallalieu is the largest of our CO2 producing fields. And it produced an average of 5,823 net BOEs during the third quarter. This rate is expected to increase, albeit a lot slower growth rate, but I want to congratulate our geological staff reservoir and operations teams, because they are developing plants right now to continue to improve rates by investigating alternative ways to flood. And there is some various production stands in East and West Mallalieu that are looking to improve rates on.

McComb and Smithdale completed the list of the major enhanced oil projects, they exhibit a production increase during the third quarter. CO2 injection rates were increased $19 million a day at McComb with the installation of new CO2 parts.

Third quarter well completions, new test facilities and increased CO2 injections should allow for the continuous production increases and improvements at McComb. Currently, McComb is producing above 1,800 net BOEs and we hope to increase it.

Tinsley, of course, is one of the largest tertiary field that we plan to operate. CO2 recall, injections began in January of 2007 at a rate of about 11 million a day. Now, we have been able to increase those rates in the pilot area to about $20 million a day right now using the existing 8-inch line. The reservoir bottom hold pressure in this pilot area, it is now about 2,000 pounds. That's almost double of what it was when we began injection first of this year.

We are constructing a larger 24-inch pipeline that's in progress, approximately 90% completed. We hope to commission it by the end of the year. Construction of the CO2 recycling facility and production facilities are proceeding pretty much on schedule, and those of you that will be attending our November 7th and 8th Analyst meeting in Jackson, Mississippi, will be able to tour that facility.

First enhance-able production from Tinsley is, again, estimated mid-2008. Denbury has several other recovery projects that are in the construction or planning phases that should add production in 2008 or early 2009, Lockhart Crossing near Baton Rouge, Louisiana and Cranfield, West Mississippi. The CO2 supply line and truck lines to Cranfield are expected to be commissioned during December allowing us to begin injection.

17 of the 19 workovers are complete in the existing field. The CO2 recycling field facility and test sites are all under construction. Enhanced oil production is scheduled during the second half of 2008 for Lockhart property. In Cranfield, which is located on the Western edge of Mississippi, it also has recycling facility under construction. We started well work and drilling operations are underway. First production is expected next year, late next year or early in 2009.

As you know, securing enough CO2 is very important to our strategy. In Jackson Dome, our CO2 source now produces in excess of 550 million cubic feet per day. That's an increase of 8% over last quarter. In January of this year we produced at a record rate... excuse me, in January of this year, we produced at a record rate of 427 million a day.

We've now improved CO2 rate to 28% above the previous record in just a few months. Even with this record CO2 production, our capacity to produce is greater than what we are now sitting down the pipeline. With the drilling of three important wells and on the dry ice field, plus modifications to the various facilities, the Jackson Dome area has a deliverability at full oil capacity between 650 million to 700 million cubic feet a day. We're going to work on our pipeline and plant facility and soon we will have enough capacity to produce at over 800 million cubic feet per day.

Even so, we have the ability to produce... we are continuously driving to maintain our CO2 supplies in capacity, keep it ahead of our tertiary rate flood requirement.

To that end, we are currently drilling two new development wells and dry ice field, both of these wells should have capacity above 90 million cubic feet a day, and those things should be completed sometime in 2008, in the second to third quarter. Our goal is to have the capacity to produce at least a billion cubic feet in early 2009.

Finally, let me conclude with the Barnett Shale, our Barnett team continues to exceed production forecast and expected results. As discussed in prior releases, the team has improved overall drilling and mechanical efficiencies, to take it to extreme, geologist, geophysics and engineers continue to hydrate our acreage positions and improve production through fract techniques.

Team has been able to use geophysics and subsurface data to analyze the geology, directionally drill at proper intervals and trajectory to maximize our production rates.

Total Barnett rates will continue to improve slightly to grow flat into future years.

With our ongoing CO2 enhanced projects, we expect our Company's total daily production to increase to 47,500 BOEs per day in 2008. Again that's a 25% increase without acquisitions.

Thank you, Gareth.

Gareth Roberts - President and Chief Executive Officer

Thanks a lot. And I would like Tracy to give us an update on the manmade sources that he has been working on?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

Thanks Gareth. As Bob mentioned, one of our goals is continually increasing the available amounts of CO2, and so we are continuing to work with multiple potential gasification projects along the Gulf Coast to acquire the CO2 that will be produced as a byproduct of their operations.

The majority of these projects are solid carbon either coal or petro, to various chemical products such as ammonium, ethanol or substitute natural gas. All these different projects are in various stages of development or financing, and all of them have different dates for expected delivery of CO2.

The projects we have executed contracts with and previously announced are continuing to finalize our efforts and are moving towards arranging final financing to begin construction in the near future.

Our best estimate of expected first deliveries at this point of anthropogenic CO2 from these manmade sources will be in early 2010. We continue to work with multiple companies and see great potential in this area for acquiring additional volumes of CO2 for manmade sources.

Gareth Roberts - President and Chief Executive Officer

Thanks Tracy. Okay. Well, I just want to reiterate one more time, we have an Analyst Meeting coming up 7th and 8th of November in Jackson, Mississippi if you want to find out the future of the oil industry there are few slots still available.

And with that I'll turn it back to our operator for any questions that we may have from the audience.

Question And Answer

Operator

Thank you, sir. [Operator Instructions]. And we will go to Noel Parks of Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Good morning.

Gareth Roberts - President and Chief Executive Officer

Good morning, Noel.

Noel Parks - Ladenburg Thalmann

Hi, I just had a few questions. Any update on McComb?

Gareth Roberts - President and Chief Executive Officer

Yes, we gave an update on McComb in the --

Robert Cornelius - Senior Vice President, Operations

Yes, we've been able to increase injection at McComb. We got to 19 million a day --

Gareth Roberts - President and Chief Executive Officer

That's an increase of 19 --

Robert Cornelius - Senior Vice President, Operations

An increase, yes, yes, we've increased to 19 million a day, we've been able to put on another test site. We've added some new wells, and yes we are seeing McComb's production, in fact, in August that we had some nice improvements.

Gareth Roberts - President and Chief Executive Officer

Yes, it seems to be slow and steady production increases at McComb.

Robert Cornelius - Senior Vice President, Operations

We're above 1,800 net BOEs per day, right now.

Noel Parks - Ladenburg Thalmann

Okay. And thinking about the earlier phases, I know for the big picture. The movement is to continue with the other phases as you build out into sort of a wider geographical footprint, but I know in the past you've talked a little bit about, for example, at Mallalieu some improvements you might make. I seem to remember something about you mentioned a day about targeting different sands and something about at East and West Mallalieu that you might be able to do something different?

Robert Cornelius - Senior Vice President, Operations

Well, these floods all have potential for improvement. What we show in our models is a very basic plan that usually involves just the main parts of the field or/and usually just one zone or two zones perhaps. But in reality these fields have all got other sands in them, either laterally or vertically, they have also got more extent of the reservoirs then we are currently flooding. So, we could extend the flood beyond our model and this is what Bob is referring to is that we have... once we get in here there is a lot more oil to be gotten out than we originally modeled.

Noel Parks - Ladenburg Thalmann

Right. In the past I guess I thought Mallalieu is more or less a single reservoir field as apposed to some of the other ones you have in the later phases, but you are saying that there might be opportunities elsewhere in the non-reservoir?

Robert Cornelius - Senior Vice President, Operations

Yes. It's actually, there is actually a series of channel sands that form... in most places it's a single sand but in other places of the field it's broken up into different sand units. And these are units that can be optimized and recovery can be optimized from them.

Noel Parks - Ladenburg Thalmann

Great. Thanks.

Gareth Roberts - President and Chief Executive Officer

So we are optimistic in that we, particularly we are talking about a slightly... one of these deeper channels called the D sand appears to have a lot of untapped potential in it right now.

Noel Parks - Ladenburg Thalmann

And do you have a sense of whether the potential numbers you have been using to date from now, whether there is upside to those, for example?

Gareth Roberts - President and Chief Executive Officer

I think there is upside overall. I wouldn't like to specifically point to a particular stand at this point but we do think that there is more reserves in these fields due to this... you basically, there is continue activity of our teams is going to improve the reserve, now the percentage of recovery is a different matter, and that's something else that we think should improve simply because we are recycling more CO2 through the reservoirs as the price of oil continues to be pretty high it allows us to be economic much longer on these individual patterns.

Noel Parks - Ladenburg Thalmann

Okay. And there was also a mention of injunction profiles at Brookhaven, some changes there could you just elaborate on that a bit?

Robert Cornelius - Senior Vice President, Operations

Yeah, we do injection profiles across all of our fields. We want to make sure that we... we call managing the molecules, and what our terms call it. As we push the CO2 in, we want to run profiles, and what those are, you go in and look and insure, as Gareth point out, it's going into the sands or to the reservoirs that you wanted to. And we do this on every field. In Brookhaven we just happen to really emphasize it over the last quarter, and that has really helped us put the proper volumes of CO2 into the reservoir, and we've seen some results from that but, it's an ongoing activity in every one of our flood.

Noel Parks - Ladenburg Thalmann

And as you improve that, does that have more an affect on the recovery growth rate or more of an affect on the cost side.

Robert Cornelius - Senior Vice President, Operations

I would call it... I think it's just more efficient... it's just more efficient. I don't think, it affects us on the recovery side because I think the reservoir is going to give what it does. It just makes it more efficient and recovers it perhaps faster.

Gareth Roberts - President and Chief Executive Officer

Well in some cases I think it will probably extend the line.

Noel Parks - Ladenburg Thalmann

Okay. And just the last thing. Any thoughts about the trends you are seeing in the service cost environment, just with the sort of up and down prices we have been seeing over the course of the year, and particularly on the gas side, which would effect the Barnett?

Robert Cornelius - Senior Vice President, Operations

I think we are actually seeing prices level off. If we look hard, I think the gas has helped us, the crude oil producers. We are also doing some things with our procurement that we are able to, be able to get some fixed pricing right now that we may have not been able to get. So, I think we are seeing a kind of a flattening in the price not an increase, since crude moves forward and the natural gas improves, but right now we have seen a little bit of flattening into the third and hopefully the fourth quarter.

Noel Parks - Ladenburg Thalmann

Okay. And just to clarify on that. As you look to 2008, and think about budget, and so forth. Do you have a baseline assumption for inflation you assume next year. Are you assuming flat next year?

Gareth Roberts - President and Chief Executive Officer

We assume flat, just as we assume flat oil prices, and of course everybody on this call knows that they are just going to continue to go up.

Noel Parks - Ladenburg Thalmann

Yes. I have no complaint this quarter about your being unhedged?

Gareth Roberts - President and Chief Executive Officer

No, no, no, but the point is that significant amount of everybody's cost are really related to energy, if you think about it, and so it won't be. If oil prices start to go up and probably natural gas prices start to increase as well, you can expect to see costs increase sometime right behind that because everybody is using fuel, people drive to work, it's going to affect everybody.

Noel Parks - Ladenburg Thalmann

Got it. Thanks a lot.

Operator

Thank you. We will go next to Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Thank you. Good morning.

Gareth Roberts - President and Chief Executive Officer

Good morning, Scott.

Scott Hanold - RBC Capital Markets

A couple of quick questions. On your assumptions, I guess, in general, where you say plus or minus 17% tertiary CO2... recovery using CO2. What oil price is that based on?

Gareth Roberts - President and Chief Executive Officer

Well, that 17% was done during... was from Shell's work on Phase I and 2. Tracy, you got what year was that. Do you think average price was during the time they were doing that?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

That was mid-80s you're talking about. Well, I guess, actually, it was closer to the late-80s, early-90s. I'd say $20 to $25 per barrel range.

Gareth Roberts - President and Chief Executive Officer

Well we abandoned about 500 barrels a day of production in Phase I, if you take the CO2 and use it in Phase III, I seem to remember. And so that was... when do we do that, probably 2001 --

Ronald T. Evans - Senior Vice President, Reservoir Engineering

2000, so --

Gareth Roberts - President and Chief Executive Officer

2000, so whatever the oil price was in 2000, that was when they saw the 17% became frozen in time because there wasn't anymore recycling going on, had we continued, we would have gotten a higher recovery from that initial area.

Scott Hanold - RBC Capital Markets

What would it take for you guys to be able to book a higher percentage, based on your recent history and sort of the current oil price environment?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

Well, Scott, this is Tracey. It's actually going to take performance and be able to project a higher number than that. As Gareth mentioned, the 17% came from Phases I and II of Little Creek, which was essentially complete with very little bit of a forecast left, and so that's where the 17% came from. Now, I mean, we actually going to go have see performance. I mean, we saw the performance at Mallalieu in a section of the field last year we were able to book higher recovery factor there, in that part of Mallalieu because we are seeing the performance of it.

So, it feels like Brookhaven, McComb, you got to... we are going to have to see actual performance for a projection of future performance that exceeds 17% before we can go above that number.

Scott Hanold - RBC Capital Markets

Okay. So, then it's more performance driven versus necessarily oil price, I know they are somewhat interrelated but you are going to have the see the performance first --?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

That's correct. Now, you can use analysis, but you still got to have something, but that does it first.

Gareth Roberts - President and Chief Executive Officer

Right. But, another fact that's going on is what we are talking about just a little earlier on the last question was that we are increasing the total amount of original oil in place that we are dealing with. So, you don't have to have an increase in recovery factor per say to increase the reserves in all these fields. You just have to basically design and implement sort of new smaller patterns and so forth, more efficient patterns to contact more oil.

Scott Hanold - RBC Capital Markets

Okay. Thank you. And one another question. I think last quarter you kind of indicated that you guys were sort of working on a recycling project on one of the field, what's the status of that, is there any update there?

Gareth Roberts - President and Chief Executive Officer

I think you referring to Olive field, where we're taking the CO2 back out of the ground and using it at McComb.

Ronald T. Evans - Senior Vice President, Reservoir Engineering

I don't have any numbers in front of me, Scott, but I mean we continue to take CO2 out of Olive and move it over to McComb and Smithdale, and we are fastly approaching our estimate of 50% recoverable CO2.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Operator

Thank you. We will go next to Eric Hagen of Merrill Lynch.

Eric Hagen - Merrill Lynch

Hey, good morning. It settle up but that really was a great quarter. Just a follow-up on Heidelberg, you mentioned that in the last call. Any incremental information that that field and when you may begin some flooding there?

Gareth Roberts - President and Chief Executive Officer

Bob, do you want to talk about that.

Robert Cornelius - Senior Vice President, Operations

Yes, we've secured a facility side, where we are securing right-of-ways for the pipeline, and the both of these would be constructed, so you won't see production of the Heidelberg until 2009.

Eric Hagen - Merrill Lynch

Okay. Great. Just a follow-up on Scott's question about the impact of higher prices on reserve booking. I guess you have to have production performance from newer fields but do you getting the significant increase from the older fields in terms of picking up say more the tale-end of reserves or is it just not that significant?

Robert Cornelius - Senior Vice President, Operations

Now we have... I don't know about significant... we run different price scenarios for bank purposes and other purposes, and there is some movement but it's not that substantial because of the fact that in our CO2 areas we are pretty much limited to the particular recovery factors. And even fields like Heidelberg and whatever, we are tied to oil cuts versus cubes which give us a fixed number. Now granted that changes a little bit, but we've had, not from our rented, I think, the difference between like our bank case and our current SEC case which we've been what second quarter, there was 2 million or 3 million barrels of difference.

Gareth Roberts - President and Chief Executive Officer

Total company.

Robert Cornelius - Senior Vice President, Operations

Total company, it's not a huge difference at this point.

Gareth Roberts - President and Chief Executive Officer

And then the other fact though, that this is still a significant. As we are keeping stay in these patents longer, so that the CO2 allocation has to change. And we are seeing some of that now, we are keeping some of the CO2 in these fields longer than we originally estimated which sort of changes the total growth profile a little bit.

Eric Hagen - Merrill Lynch

Great, that's really helpful. My last question was for Gareth, you've given a better oil price forecast, the marine house is staying unhedged and what not, what do you see going forward with oil approaching 100. I mean where do you think breaking point is, when do you think you would consider maybe putting some hedges on.

Gareth Roberts - President and Chief Executive Officer

Well, we only put hedges on it, if it was, if we really felt our balance sheet was threatened by some event, I think, because I just don't see any change in the current situation where you basically got declining global production. And you know potential demand that significantly higher than that, because it's not going to get filled because there is actually no oil to fill it. So, as long as that scenario goes on you really are going to be in a rising price environment, so it's hard to hedge at any time in that sort of scenario. Best, I think, keep a strong balance sheet so that you don't have to hedge for the downside. And you know what we are doing this year is we are selling our Louisiana primarily gas assets. We are dropping down, as we say, are sort of effectively selling our two pipeline systems into Genesis GEL. In order to provide us with the sort of strong balance sheet that means that we don't have to worry about hedging in certainly 2008 anyway.

Eric Hagen - Merrill Lynch

Great. Thank you very much.

Gareth Roberts - President and Chief Executive Officer

Thanks.

Operator

Thank you. [Operator Instructions]. We will go next to Steven Black of Jefferies & Company.

Unidentified Analyst

Hi. I want to see if we could talk a little bit about the Barnett, specifically I was interested in where you are... and I know that you are drilling or you hold more acreage in Parker County, but I was hoping that maybe we could get a little more information on your drilling activities in Parker versus your other South and West areas?

Robert Cornelius - Senior Vice President, Operations

The majority of our drilling is going to be in Parker County and I guess we can... I think it's pretty insignificant, but we are looking at a transaction in Ellis County, so we will probably not be drilling an Ellis any longer. Does that answer your --

Gareth Roberts - President and Chief Executive Officer

Yeah, I mean, we haven't drilled any wells this year, I don't think so.

Robert Cornelius - Senior Vice President, Operations

That's absolutely --

Gareth Roberts - President and Chief Executive Officer

So. Yes, we have been focusing on Parker and occasionally a neighboring, close to that area. Sometimes just gone outside the county, I think, but.

Unidentified Analyst

And I believe your earlier comments. You said that your engineering staff has done some work on some your completion techniques and so forth. Can you elaborate a little more on that?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

Well what they are doing is. They are looking at how they frac, and they are doing stage fracs, so they will take the horizontal well board and break it into stages and frac it, and then we are also... they are doing some fracing with adjacent wells pretty much simultaneously. By simultaneous, I mean, one-day one-well, and the next day the adjoining well to the one. So they are trying to pack the reservoir with energy. The more energy you put in the reservoir, the rock, the easier it is to frac. So, what we are trying is to have see how much horse power we can put on a well in a 48-36 hour period and frac the wells that way. It's... so, and we're breaking into smaller pieces. So, we make sure that we contact the rock with our fractures.

Gareth Roberts - President and Chief Executive Officer

I think that also got very efficient as far as been able to drill these wells and to get them on production.

Ronald T. Evans - Senior Vice President, Reservoir Engineering

Yes, I mean, that's another real plus for us too. The teams really... been able to reduce the number of drilling days and reduce the number of connection days. Connection days mean the time the rig released to actual sales. And those two things combined, plus this fracturing has been able to really accelerate and help our Barnett stay above the forecast.

Unidentified Analyst

Can you tell me how many days, it's taking you to drill the well now?

Ronald T. Evans - Senior Vice President, Reservoir Engineering

Yes, it depends on the well, depends on the depth, it depends on the horizontal, but probably 16 to 17 days now from spud to release.

Gareth Roberts - President and Chief Executive Officer

And what would've that been say a year --

Ronald T. Evans - Senior Vice President, Reservoir Engineering

It was 20, 22 days or even longer in some cases. We actually had one well go almost 30 days, certain problems.

Unidentified Analyst

And how many net producing wells do you have now in the Barnett?

Robert Cornelius - Senior Vice President, Operations

Net producing, I don't have an exact number in front of me, it's probably somewhere around 80 horizontals. We have another --

Gareth Roberts - President and Chief Executive Officer

20, 30.

Robert Cornelius - Senior Vice President, Operations

Yes, probably 20 or 30 net wells that are verticals, but they don't contribute much to the production.

Unidentified Analyst

And you've mentioned about adding, I guess, some... looking at something in ERAP, did you add anything to your acreage position in Q3?

Gareth Roberts - President and Chief Executive Officer

I think we are always adding small pieces to our acreage position. I would say. I don't... how many specific numbers for Q3 --

Robert Cornelius - Senior Vice President, Operations

... specific numbers but we're only targeting Wayne, Erath [ph] and Parker Counties.

Gareth Roberts - President and Chief Executive Officer

And as usual, acreage within our sort of core area.

Unidentified Analyst

So you are still at about 50,000 net acres.

Robert Cornelius - Senior Vice President, Operations

Yes, on an overall basis.

Unidentified Analyst

Okay. Great. Thank you very much.

Operator

Thank you. We'll go next to Nicholas Pope with JP Morgan.

Nicholas Pope - JP Morgan

Good morning.

Gareth Roberts - President and Chief Executive Officer

Good morning.

Nicholas Pope - JP Morgan

I was hoping talk a little about what the acquisition for fields... what that market looks like right now in the Gulf Coast, and would any activity to add additional field, is that going to be dependent on supplies from these regen [ph] sources becoming available?

Gareth Roberts - President and Chief Executive Officer

Yes. I mean, one way to look at it is basically the fields that we have in our presentation Phases I through VIII. The total amount of CO2 required to do those is actually very close to what I would guess our total amount of CO2 proven at Jackson Dome is right now. It was a little bit short at the beginning of the year but we've added more reserves at Jackson Dome, and we'll find out exactly how many more reserves at the year end, but assuming we've added some more reserves. It's very close. So, really the model that we have out there is just our current CO2 proven.

In addition to that you know we've got probable CO2 reserves at Jackson Dome, and then we've got these anthropogenic sources that we basically have taken the position that once they start constructing we'll go out and find another field to flood. So, we haven't been in particular hurry to buy additional fields.

Nicholas Pope - JP Morgan

Got it. Thank you.

Operator

Thank you. And with no further questions, I would like to turn the conference back over to Mr. Gareth Roberts for any additional or closing remarks.

Gareth Roberts - President and Chief Executive Officer

Okay, well, thank you everybody; and we'll see you again next quarter.

Operator

Thank you for your participation. That does conclude today's conference. You may disconnect at this time.

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