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Denbury Resources Inc. (NYSE:DNR)

Q1 2008 Earnings Call

May 1, 2008 11:00 am ET

Executives

Gareth Roberts – Chief Executive Officer and President

Phil Rykhoek – Chief Financial Officer

Ronald T. Evans – Senior Vice President of Reservoir Engineering

Robert Cornelius – Senior Vice President of Operations

Analysts

Michael Scialla - Thomas Weisel Partners

Joseph Allman – JP Morgan

Jeffrey Robertson - Lehman Brothers

Armine Benali – John Hancock Advisors

Tom Gardner - Simmons & Company

Andrew Coleman - UBS

Noel Parks - Ladenburg Thalmann

Jeffrey Hayden - Pritchard Capital Partners

Operator

Good day everyone and welcome to this Denbury Resources 2008 first 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 could cause such a difference that can be found in our reports filed with Securities and Exchange Commission, including our reports in 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.

Gareth Roberts

Thank you, Mark. Welcome everybody to Denbury’s first quarter 2008 conference call. In the quarter, we earned $73 million, $0.30 a share reported, but if you take into account the $24.4 million after-tax non-cash charge related to hedging it would have been $0.39 a share, so that’s the clean number.

Overall production was 44,900 BOEs a day and tertiary production was 17,156 barrels a day. Both were about the same as the fourth quarter 2007 adjusted for the property sales.

The production for the tertiary was affected by some mechanical problems, but actually not far from our original forecast, which we’re projecting as being about flat. And we are projecting our big increases to occur later in the year.

Overall, we are still maintaining our production forecast for the year. I have with me today Phil Rykhoek, our Chief Financial Officer; Tracy Evans, our Senior VP of Reservoir Engineering, and Bob Cornelius, our Senior VP of Operations.

I’d like to turn it over to Phil now to discuss the financial results.

Phil Rykhoek

Thank you, Gareth. As he mentioned, I just would like to clear up, there has been a couple of releases this morning that said we missed earnings forecast, and as Gareth said, we did have $38.7 [million] non-cash mark-to-market value adjustment on our derivatives, which is $24.4 million after-tax.

That equates to $0.10 per diluted share which would give us $0.39 of clean earnings, per diluted share, which is actually several cents ahead of First Call, and I think it’s pretty close to what the Street would say.

Gareth Roberts

Did I mention I hate hedging by the way?

Phil Rykhoek

Looking at the quarter as I normally do, I’m going to compare this quarter to the last quarter, in other words, first quarter 2008 to fourth quarter 2007. If you exclude about a $10 million tax adjustment that we made in the fourth quarter of last year relating to changes in our statutory rate, almost all of the $23 million decrease in income between this quarter and last quarter relates to our derivative contracts.

This quarter we had the $38.7 [million] charge primarily relating to a decrease in the value of our 2008 natural gas swaps. If you’re not familiar, those were swaps we locked in just under $8 per Mcf on 16 million cubic feet per day last fall, representing around 70% of our forecasted production. As a result of the increase in natural gas prices, these swaps have declined in value and so we did a mark-to-market adjustment.

We had fair value charges in Q4, but they were only $11.8 million, and those were primarily related to the little bit of oil swaps that we have in place that go back to our January 2006 acquisition.

In addition to the non-cash charges, we paid out significantly more cash on our derivatives this quarter, making payments of $8.0 million, primarily on the oil swaps as compared to collections of just under $1.1 million in Q4.

So in total, when you look at the derivative impact on the sequential quarters, during the first quarter of 2008 we had incremental non-cash charges of $26.9 million, higher net cash payments of $9.1 [million], or a net pre-tax decrease in income of $36 million, which on a tax adjusted basis, is $22.7 [million].

That accounts for almost all of the quarter-to-quarter decrease in net income. Of course, there’s other changes, but they in essence, net out against one another. We did have significant increases in commodity prices, offset by the decrease in production primarily related to our Louisiana property sale.

NYMEX oil increased from an average of $91 in Q4 to $98 a barrel this quarter. NYMEX natural gas increased from about $7.35 to about $8.70. As a result, our net average price received per BOE increased 12% sequentially from $68.61 per BOE to $76.65.

But as I mentioned, the 12% higher prices were approximately offset by the lower production again relating to our Louisiana sale.

As you know, we sold most of our Louisiana natural gas production late in 2007, and closed on the balance in February 2008, and we received net aggregate proceeds of about $157 million. These properties produced 5,097 BOEs a day in the fourth quarter of 2007, and we recorded 302 BOEs a day this quarter.

That amount represented the production during the period between January 1 and our closing date on that remaining 30% of the sale that closed in February. So if you adjust for that sale, our production was approximately flat quarter-to-quarter.

Similarly, as Gareth mentioned, our tertiary production was approximately flat. And I think Bob is going to talk more about production in detail and go through it by field here in a little while.

We are leaving our 2008 production forecast unchanged at 49,000 BOEs a day; tertiary forecast unchanged. Although based on the results at the end of April, it looks like our 2008 results will be at the lower end of that tertiary production range.

To briefly highlight other financial items, the oil and NYMEX differentials improved a little bit over Q4. We averaged $6.50 per barrel below NYMEX as compared to $7.27 per barrel below NYMEX in Q4. That’s a result of having a little bit less liquid production in the Barnett, which sold at about a $40 per barrel discount this quarter and overall market conditions.

Natural gas differentials worsened somewhat to a negative variance of $0.90 per Mcf in Q1 versus $0.55 per Mcf in Q4. This decrease was due to rising natural gas prices, which usually increase our differentials and the sale of our Louisiana natural gas properties, which historically received a premium to NYMEX.

So I would expect at least based on current market, this quarter’s differentials will be somewhat representative of the future since most of the Louisiana property sale was out of this quarter.

Our operating costs increased 3% sequentially on a gross basis but 17% sequentially on a BOE basis from $13.78 per BOE in Q4 to $16.15 this quarter. The sale of our Louisiana properties was the biggest component of this increase as the natural gas properties had lower operating costs.

If the properties had been sold in Q4, the operating costs would have been $1.04 higher or $14.82 per BOE on a comparative basis. The balance of the increase primarily relates to our growing tertiary emphasis and higher commodity prices.

The tertiary LOE per BOE increased 5% sequentially from $19.90 per BOE in Q4 to $20.81 this quarter, the increase primarily due to higher energy costs.

As we mentioned in the press release, you might want to note that beginning January 1, we began capitalizing CO2 injected costs in the fields that have not yet seen an oil production response to the CO2 injections. Whereas previously, we expensed all injected costs.

The accounting theory behind this is that prior to a production response, the tertiary floods are in a development stage of life and therefore the injection costs should be capitalized. Once the fields start producing incremental oil as a result of the injections, the fields are considered to be in their productive stage of life, and at that point, all subsequent CO2 injected costs would be expensed as would other production costs.

Had we continued with the prior accounting methodology of expensing all costs, we would have expensed an additional $2.9 million in the first quarter of 2008 or approximately $0.70 per BOE. That’s mainly because there were significant injected costs during the period in fields without tertiary related production, primarily at Tinsley and Lockhart Crossing, two of our new fields.

We have seen some initial production response, at Tinsley during April. Production response is not expected from Lockhart until the third quarter. This change in accounting methodology was not material in 2007. As for example, during Q1 of 2007, only $116,000 would have been capitalized under the new procedure.

Looking forward, we would expect our operating cost per BOE to be in the $16 range most of the rest of the year, perhaps a little less late in the year with the anticipated production increases.

G&A came in about $1.7 million higher sequentially, the increase primarily attributable to higher compensation and personnel costs. We continue to expand and grow. We increased our employee head count 15% in 2007 and we’ve gone up a little bit again this quarter.

Further, the first quarter is usually one of the higher cost quarters because of year-end items such as audits and so forth. We expect 2008 to generally be between $3 and $4 per BOE, probably gradually decreasing on a per BOE basis throughout the year along with the production increases. I might just add that there were little or no G&A savings from the Louisiana property sale.

During the first quarter of 2008, we had net bank repayments of about $39 million; that’s primarily as a result of the proceeds from the last portion of the Louisiana property sale, and we repaid quite a bit late in 2007. So our average debt levels decreased from $766 million in Q4 to $662 million this quarter, a 14% reduction in average debt levels.

In addition, our capitalized interest increased approximately 10% from $6.6 million in Q4 to $7.3 million as a result of continued spending on properties without proved reserves. On a net basis, our interest expense decreased $2.8 million sequentially.

As of quarter end, we had $636 million of debt outstanding, which consisted of $525 million of sub debt; $111 million of bank debt. We borrowed an additional $20 million during April, so we have $656 million of total debt as of today.

I might also note that as of April 1 our bank borrowing base increased from $500 million to $1.0 billion, leaving us with plenty of potential available credit should it be needed or desired. We are still working on our $250 million dropdown transaction with Genesis, of which $25 million of the proceeds will be Genesis units, which once closed should leave us with no bank debt and close to $100 million of cash.

As we’ve discussed before we’re likely to account for both of these Genesis dropdowns as capital leases, which means the estimated payments of $30 million per annum will be booked as principal and interest. I’m not going to give you a projected closing date for these transactions, but we do believe closing is very soon.

Our DD&A on oil and natural gas properties didn’t change much. It increased less than 1% sequentially from $10.96 per BOE in Q4 to $11 per BOE in Q1.

Lastly with regard to income taxes, our net effective rate this quarter was slightly lower, approximately 37% instead of 38%, as the higher pre-tax income allowed us to take a slightly larger 199 deduction. Our current taxes as a percentage of the total provision increased to almost half of the total provision.

We will be unable to take tax deductions on most of our CO2 pipeline expenditures during 2008 as these lines won’t be in service this year, and that is a significant portion of our 2008 spending.

This factor has become more significant as commodity prices have increased and our income has risen according. So therefore, as our income goes up, most of that is subject to current taxes.

So for 2008, based on where we’re at right now, we would expect our total tax rate to be between 37% and 38% with cash, or current taxes, about half of the total provision, much as it that was in the first quarter.

With that, I’ll turn it back to Gareth.

Gareth Roberts

Thanks. Bob is going to talk a little about production.

Robert Cornelius

Thank you Gareth. As Phil reported, the first quarter production averaged 44,900 BOEs per day, and that’s approximately the same as in fourth quarter 2007 after adjusting for the Louisiana property sale.

As we predicted during our February earnings call and our analyst meeting held earlier this month, total first quarter company production would be very close to forecast. And that average enhanced oil production of 17,156 BOEs per day would be approximately flat when we compared it to the fourth quarter of last year.

Now the reasons for the EOR production shortfall are mostly attributable to unforeseen mechanical or weather-related incidents. A couple of these unforeseen incidents with normal field fluctuation and well responses and some equipment startups created the first quarter production lag.

Even though enhanced oil production through the first quarter or through April have been lower than originally forecasted, we are maintaining our same production range of 22,000 to 25,000 BOEs per day of enhanced oil production.

But as Phil pointed out, we are guiding you toward the lower end of that range as it will be difficult for us to make up that lost production during the first quarter. However, I want to point out, even 22,000 BOEs per day is almost a 50% increase over the 2007 average rate of 14,757 BOEs per day.

Let me dive just a little bit deep into the detail. I’ll start with Phase I. That’s our more mature tertiary oil production area. We averaged 12,864 net BOEs during the fourth quarter 2007. That was down 688 BOEs compared to the fourth quarter of 2008.

Our McComb and Smithdale complex as well as Mallalieu, our two largest programs, they had significant downtime associated with these unexpected mechanical failures, or process upsets, that resulted in the reduction of enhanced oil production. Weather conditions, both cold weather and electrical storms, as well as some wet weather, also hindered our operations during that period.

Mallalieu is our greatest oil producer, and it produces approximately 50% of our oil production in Phase 1. Mallalieu averaged 6,900 BOEs during the first quarter down about 205 during the quarter when compared to the fourth quarter.

Besides the planned shutdowns for routine maintenance and repairs, we also experienced two major compressor failures that reduced throughput capacity and thus significantly reduced tertiary oil.

Our operations team had previously recognized that we had two huge compressors installed during the 2002 facility construction. We knew these needed to be replaced, and we had rescheduled these replacement compressors during 2008.

Unfortunately, installation is scheduled for May of 2008, and the old compressors failed during March. The new compressors and the associated equipment are now on our locations and we expect this new compression to be operational mid-May, of course, better run times equal better and improved production.

Now the McComb-Smithdale area showed the largest decrease in tertiary oil production. This area averaged 1,632 BOEs during the fourth quarter of 2008. That’s down 464 net BOEs when compared to the fourth quarter.

As previously reported, the best well in our Smithdale area, which produced approximately 350 gross BOEs per day, had a tubing casing failure and that resulted in the well being plugged.

The replacement well was drilled and completed during April. Initial results from that well are very promising. We had several more oil producers and CO2 injection wells that are currently being drilled in this field and that should increase our rates in Smithdale.

At McComb, the team has increased the CO2 injection rates with the installation of the new CO2 pump. We have several producers that are responding to the increased CO2 injection, and we are expecting oil production rates to increase.

Now Brookhaven Field, also in Phase I, we had 2,507 net BOEs during the fourth quarter. That was an increase of 131 net BOEs compared to the first quarter of this year.

The recycled field reached peak capacity in December 2007, which capped our production growth. We’ve now installed a new compressor, and still the upgrades were performed in late January in tertiary production, now it has continued to improve.

We also have plans to expand Brookhaven by adding new injections and producers into Phase IV and Phase V of that area.

Phase II, which is Southeast Mississippi, continues to improve and is above expectations, Phase II consisting of Eucutta, Soso and Martinville. Soso averaged 1,109 net BOEs during the fourth quarter of last year; it continues to increase to an average of 1,488 BOEs during the first quarter of 2008. This is the second straight quarter of plus 30% growth in that area.

In Soso, we continue to rework existing wells and add an increased CO2 injection. Now, we are slightly behind in some of our well conversions, but the reservoir itself is performing as expected, as producing wells and injection to withdrawal ratios are very good. We expect production to continue to increase throughout the year at Soso.

Eucutta has increased from 2,572 net BOEs in the fourth quarter of 2007 to an average of 2,699 BOEs during the first quarter. That’s a 5% increase in that field. The tertiary oil production has exceeded our expectations in 2007.

As a result, the CO2 recycling rates have also exceeded our expectations. However, because where we knew we were in our planning, we’ve accelerated the installation of compression to increase recycled compressor rates by 20 million a day. And we have ordered an additional 100 million a day for that facility that we plan to complete by the end of this year.

We also continue to work in Heidelberg CO2 recycle facility. We’ve acquired right-of-way to begin the construction of a 16-inch CO2 line, and that will connect to the Free State Pipeline.

So the pipeline laterals should be completed during the fourth quarter of 2008, and CO2 injection started by year-end. Construction will continue on the CO2 facility in 2009, and we should have our first production some time in 2009 from Heidelberg. That’s a very important project, and it is on schedule.

Phase III is Tinsley. And the Tinsley Field is the largest tertiary field that we operate with potential enhanceable reserves of approximately 40 million barrels of oil. Now recall, CO2 injection began in January 2000 at a rate of about 11 million a day. Once the larger 24-inch pipeline was constructed, CO2 injection ramped up to 60 million a day and we are now injecting in excess of 100 million a day into the Tinsley reservoir.

The Tinsley production recycle facilities are completed and in operation, and during the last weeks of April, the Field officially produced its first tertiary oil. We are both encouraged and optimistic about the initial production.

Denbury has another enhanced oil recovery project that should also add production during 2008. Lockhart Crossing near Baton Rouge, Louisiana, CO2 injections began on December 7, 2007.

We are presently injecting 30 million cubic feet into six different CO2 injection wells. The CO2 recycle and testing sites are nearing completion. We are awaiting the completion of electrical substation in late June and expect 8 to 10 wells to be ready to flow during the third quarter.

At Cranfield, our Western most field in Mississippi, continues to be revitalized as we convert this field from a nearly abandoned reservoir to a tertiary project. Facilities are under construction. We have wells being reworked. We have 4 injection wells drilled, and the 16-inch pipeline that’s going to supply CO2 was refurbished, inspected and pressure tested.

We expect to begin commissioning this line in the second quarter of 2008 followed by CO2 injection into the reservoir. The first Cranfield CO2 tertiary production is not expected until late 2008 or probably first quarter 2009.

And as you know, securing enough CO2 volume is important to our strategy. Jackson Dome, our CO2 source, averaged 554 million cubic feet during the first quarter. On our report in April, our CO2 production has increased to 640 million cubic feet per day on average. So our Jackson Dome continues to add CO2 volume, plans for expansion and preparing for future projects.

We have an effective production capacity of about 700 million per day right now. Currently, we have 2 development wells being drilled to further increase the supplies. We also are in the final stages of completing an additional 300 million cubic feet per day dehydration facility.

Both of these projects should put us at a capacity of close to a Bcf per day. We are also adding pump capacity to the NEJD pipeline system, and that work will be completed second quarter, and it will allow us to ship or transport more CO2 down that NEJD pipeline.

That’s the CO2 enhanced oil recovery. Denbury’s unconventional gas play, the Barnett Shale in North Texas and the Selma Chalk in Mississippi both did very well during the first quarter. The Barnett Shale averaged 12,800 BOEs per day or approximately 76.8 million cubic feet per day.

In the Barnett, we currently have 2 rigs running and we expect to continue to deploy those 2 rigs throughout the balance of the year. We expect this new production to offset the natural declines. So we are forecasting Barnett Shale to be relatively flat profile through 2008.

I think also I need to report that we sold our non-producing Erath and other southern counties in the Barnett Shale, and Denbury received approximately $2.6 million for the various transactions on about 17,400 net acres.

We determined that investing the same capital dollars into our core acreage in Parker and Wise gave us a much better rate of return than some of these southern counties.

With that Gareth, I’ll turn it back to you.

Gareth Roberts

As people know, we are looking very hard at man-made sources here too. So I am going to ask Tracy to give this kind of update on his work in that arena.

Ronald T. Evans

Thanks Gareth. We continue to work on various levels with proposed gasification projects in order to increase our total available CO2 deliverability. To date, we have not entered into any new CO2 purchase contracts other than the 3 that have been previously announced, although we have signed several confidentiality agreements, letters of intent, or memorandums of understanding with additional proposed projects.

Generally, we entered into these confidentiality agreements, letters of intent, or memorandums of understandings until such time as the proposed gasification project is confident that they are going to move from concept and initial design into their final engineering and design, financing, and then construction.

Two of the 3 existing CO2 contracts with the proposed projects are in the final stages of final engineering and design, and plan to move into the financing stage later this year. Several of these other proposed projects that we have not signed CO2 contracts with, appear to be nearing a point in which they may be interested in negotiating a final CO2 purchase contract.

Based on these existing agreements, either an MoU or an LoI, with these other proposed projects, we would expect the final CO2 purchase contracts to be very similar to the existing 3 CO2 purchase contracts that we have.

Based on the current development construction schedules for the first of the projects, we expect to receive anthropogenic CO2 in late 2011 or early 2012. This date depends upon the projects successfully finishing their final engineering design and arranging for appropriate financing to construct the project.

In addition to negotiating with proposed gasification projects, we are also discussing the opportunities to capture existing CO2 volumes from existing projects or plants out there today, although those volumes from these sources are generally much lower than the proposed gasification projects are.

Finally, we continue to monitor developments in Washington, D.C. and in various state capitals. While there is still no consensus on what final carbon legislation and/or carbon credit legislation might eventually get signed into law, it does appear that it would be very difficult to obtain all the necessary permits and regulatory authority to construct an industrial coal project without securing a CO2 solution.

Thus, we feel Denbury remains well positioned to secure additional CO2 supplies from currently proposed gasification projects.

With that, I will turn it back to Gareth.

Gareth Roberts

Thanks, Tracy. And then, some of you may have caught Tracy on C-SPAN and other channels testifying before Congress.

In summary, we are very excited about some of these upgrades that we are doing to the tertiary projects. We’ve got new compressors coming in. We’ve got various plant upgrades scheduled. Hopefully, they’re going to occur on time, and we should see some pretty good results.

Bob mentioned that we are seeing oil production at Tinsley for the first time, which is very exciting, and we’ve got great plans for that.

So with that, I’d like to bring Mark back on the line and see if we’ve got any questions.

Question-and-Answer Session

Operator

Our first question comes from Jeffrey Hayden - Pritchard Capital Partners.

Jeffrey Hayden - Pritchard Capital Partners

Sorry if I missed this if you mentioned it, but what are your expectations for production volumes in Q2, and then could you give a little color on the ramp you think in Q3 to Q4 to get to the 49,000 [BOEs]?

Gareth Roberts

We don’t know; we haven’t normally given forecast by quarter. But mathematically, it’s straight up from here. So you could probably figure it out.

Jeffrey Hayden - Pritchard Capital Partners

Okay. So it’s a pretty even ramp throughout the year to get the 49,000?

Gareth Roberts

As best as we can tell. Of course, as you know, the real world is a little bit different. And it sometimes you have stair steps and in our case, we get tremendous, on a daily basis, sometimes you get real big leaps. And then it’s flat for a while and then it leaps again. But overall, that’s what we are forecasting. This is about an average increase for the rest of the year.

Jeffrey Hayden - Pritchard Capital Partners

All right. Thanks a lot.

Operator

Our next question will come from Noel Parks - Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

I was curious, could you maybe go into a little more detail about what has been happening at Tinsley? You said you’ve seen the first oil response there. And as you move into the various phases at Tinsley, where you stand with those?

Gareth Roberts

Bob, do you want to take that one?

Robert Cornelius

Noel, what we’ve done is we’ve put on at the first of the month some...

Gareth Roberts

Just tell us the number of wells.

Robert Cornelius

We put on initially 5 different wells, and you’ve been out to these facilities, they’re very large, and you have to bring those facilities up and commission those facilities. You have to fill tanks. You have to fill all those separators and heater treaters. So we’ve been doing that process.

We’ve added, I think we are up to 10 wells now producing. But I’m not quite sure we’re ready to release a volume in that because of some of the measurements. As you fill these separators, and you’ve seen how large they are, it can throw your volumes off quite a bit. So we’d rather retain that until next month or so and then we will get out some volumes.

Noel Parks - Ladenburg Thalmann

And referring to the prior question where you talked about a stair step effect, at Tinsley, do you have a sense of when, maybe over the next year or so, which quarters you think you’ll see the biggest increases there?

Gareth Roberts

I wish we knew it exactly, but as we mentioned in the main call, we are very pleased with the initial response. It’s ahead of what we thought it would be.

Noel Parks - Ladenburg Thalmann

Okay.

Gareth Roberts

But we don’t want people to get too excited because its swings in roundabouts. If you brag about Tinsley’s response, at the same time, you’ve got other fields that are lagging their projected response. And then they catch up and then perhaps Tinsley will drop back. So, we don’t anger the production gods. We are not actually going to release these figures for Tinsley.

Noel Parks - Ladenburg Thalmann

Okay, clear enough.

Gareth Roberts

[Inaudible] on that, but it’s all going to be in the mix in the second quarter.

Noel Parks - Ladenburg Thalmann

Okay. And also at McComb and Brookhaven, you were talking about some of the different equipment-based and weather-based issues you had there. Has the production response, with those factors backed out, has it continued roughly according to your expectations or better or worse?

Gareth Roberts

What we’ve seen is that when we’ve had these shutdowns, it has an arithmetic effect. If you lose production for 3 days or something, it’s very hard to catch back up the average. So, overall, yes, we’ve been pretty pleased with the response on patents and things like that. But some days, where we’ve been shut down or had a mechanical problem, it’s contributed to the overall production average.

Noel Parks - Ladenburg Thalmann

Okay. That’s it from me for now. Thanks.

Operator

Our next question comes from Andrew Coleman - UBS.

Andrew Coleman - UBS

I had two questions. First, thinking about the mechanical issues that happened with your CO2 injection, how long do you think it takes to recharge everything?

Gareth Roberts

Are you talking about the facilities or the reservoir?

Andrew Coleman - UBS

Reservoir.

Gareth Roberts

The reservoir is not actually the problem when we have these mechanical problems. It’s the facilities. Usually it takes like 3 days to get the facilities back up lined up again, so we get back to full production. So any kind of minor shutdown causes 3 days of lost production, and that’s what we’re referring to.

A downhole, you do have some problems when we were trying to recover that lost well at Smithdale, we shut down the injectors around that so that we could actually work on the well because the downhole pressure is actually quite tricky for you to work on the well.

So we shut those injectors down, and only have recently started that injection back up again. So there are some delays that occur when you have mechanical problems like that. But generally speaking, once the initial response has been obtained, we see the effect of increasing or decreasing volumes of CO2 actually pretty quickly in the production in a matter of days.

Andrew Coleman - UBS

Okay, great. And then looking at the differentials there for the oil side,is it best to think of that more as related to the pipeline cost? Or is that more of just a quality differential based on the types of oil coming out of your various tertiary plays?

Gareth Roberts

It’s a quality differential. There are not any special additional costs for transportation that would be different from any other area.

Andrew Coleman - UBS

Okay, but then across the operations though, you have a small hiccup there, but everything is moving along as planned then?

Gareth Roberts

Yes, overall, we’ve made a lot of progress, although it’s not showing up in the production numbers; we feel we’ve made a lot of progress in the first quarter.

Andrew Coleman - UBS

Okay. Great, thanks a lot.

Operator

Our next question comes from Tom Gardner - Simmons & Company.

Tom Gardner - Simmons & Company

A couple of things. Can you give us a progress report on the Faustina Plant construction and give us an update on your Green Line; I know you will be starting that construction late 2008 last I heard. When do you anticipate having that in the ground?

Ronald T. Evans

I will take the Faustina project. The Faustina project is in the final engineering and design. The latest schedule they’ve provided us is that that process ought to finish probably very late second quarter.

They enter into their financing in the third quarter and hopefully construction either late 2008, early 2009. So we think that will probably be the first project still. So, it takes about two and half, three years to construct, so that’s where you get to the late 2011 timeframe.

Gareth Roberts

It has taken longer, hasn’t it, than we originally projected to get to this stage, but I don’t think you should read anything into that other than the fact that these projects do always take a little bit longer. Just simple permits for construction seem to take longer than they ever did before.

Robert Cornelius

On the Green Pipeline, we’re about 90% permission in Louisiana for surveying; 87% permission for surveying in Texas. We have already started purchasing right-of-way in what we call Phase I part of the pipeline in Louisiana. We’ve begun to roll our first segment of pipe, or manufacture our first segment of pipe at that plant.

We’ll receive our first set of contractor bids next week. We will have our bids in. So that project is moving on, and yes, we are looking at putting some Phase I pipe in the ground during the fourth quarter.

Gareth Roberts

And final completion?

Robert Cornelius

Final completion still end of 2009.

Tom Gardner - Simmons & Company

Okay, thanks for that Bob. And Tracy, you ran through your contract negotiations and the various statuses there for CO2 purchase along that line. Has the slowdown in the US economy impacted that?

And are all the contracts that you’re currently negotiating, is that for high-pressure discharge? I understand there is quite a bit of savings there in high pressure versus low pressure.

Ronald T. Evans

No, all of our contracts, we expect to sign are based on the project actually delivering high-pressure CO2, generally greater than 2,000 pounds into the pipeline. As far as a slowdown, I don’t know if the slowdown necessarily in the economy has hurt these projects.

I think it’s more a fact of these guys getting all their final engineering designs done and getting final off-take agreements. Then eventually, I don’t know that the credit markets helped a lot either here over the last few months.

But that seems to be clearing up as well a little bit. I think it’s a combination of things. A lot of it’s just these are huge projects, the smallest ones are 1.5 to 2 billion and they go up from there.

Gareth Roberts

In fact, the economy is too good for this type of work that the costs are going to always be higher and the equipment is always going to be in short supply. And that’s more of an issue I think than anything else.

Tom Gardner - Simmons & Company

Okay, great. One last question and I’ll get off. The Smithdale well failure, was that a one-off or do you see something systemic there?

Robert Cornelius

I think it’s a one-off. Because you are dealing with CO2, we have tubing leaks and things like that, but that’s a one-off where you lose a well.

Gareth Roberts

We haven’t had that happen before.

Robert Cornelius

No sir.

Tom Gardner - Simmons & Company

Thanks.

Operator

Our next question comes from Armine Benali – John Hancock Advisors.

Armine Benali – John Hancock Advisors

I wanted to ask you about the McComb and Mallalieu. I’m not sure I understand yet what the actual production potential is or what are your expectations for the potential is from McComb particularly?

Gareth Roberts

I don’t think we’ve projected individual fields, have we? On that basis, we’ve projected Phase I. What are the numbers overall for Phase I for the year? I think we put that out I think in one of the press releases.

Robert Cornelius

For the year on the McComb we’re slightly 2,000 barrels per day net to Denbury.

Gareth Roberts

That’s the overall number?

Robert Cornelius

That would be overall for McComb.

Gareth Roberts

Yes.

Armine Benali – John Hancock Advisors

Okay, all right. And can you give me the same number for Brookhaven too, since it is one of the other bigger ones?

Gareth Roberts

The overall average for the year would be...

Robert Cornelius

Around 3,800 barrels per day.

Armine Benali – John Hancock Advisors

Okay.

Gareth Roberts

Are those net or gross?

Robert Cornelius

That’s net.

Gareth Roberts

Okay.

Armine Benali – John Hancock Advisors

Okay, so those are net numbers.

And again, maybe you don’t want to give out these numbers, but do you have any planned production for Q1 what you were expecting? And is that for McComb particularly?

Gareth Roberts

We were projecting initially to be fairly flat to Q4 and then it’s just a few hundred barrels behind that because of these things that Bob has been outlining.

Are you talking about Q1 or are you talking about Q2?

Armine Benali – John Hancock Advisors

Just Q1.

Gareth Roberts

Really we are not that far-off from what we thought it would be because of the timing of the way that these floods work and the timing of our increasing injections and that sort of thing.

We weren’t expecting too much in the first quarter. I think we’ve indicated that all along that we weren’t expecting too much of an increase. But then we’d have these odd mechanical problems as well that reduced it a little bit too.

Armine Benali – John Hancock Advisors

Okay, and for Brookhaven, I think you said that you had a compression issue in that field?

Gareth Roberts

We hit the maximum recycling capacity pretty quickly there. That means adding on to additional compression, and we have plans to do these things. But the exact moment when you need the new compressor is a bit more of an art than a science. Sometimes we are waiting on the next round of compression to increase the production of the field.

Armine Benali – John Hancock Advisors

Okay, so this is a different issue from what you experienced here maybe a couple of year ago at McComb right?

Gareth Roberts

It’s completely different. This is all surface mechanical stuff, just trying to get the facilities lined out and maximized and without having to spend all the money up-front.

Armine Benali – John Hancock Advisors

Okay, all right. Thank you.

Operator

Our next question is from Jeffrey Robertson - Lehman Brothers.

Jeffrey Robertson - Lehman Brothers

Thanks. Bob, you talked about the production growth at Soso. Can you talk about what the trajectory of that field is expected to be over the course of 2008 or has it really already had its big boost in production?

Gareth Roberts

I think we’ve got very steady increases; those were very steady producers...

Ronald T. Evans

Yes, I’d rather not give out a whole bunch of these because what you do is when you put the CO2 in, you ramp it up and you’ll hit a plateau and then you’ll put a new phase on, ramp up and hit another plateau. And it’s very difficult to...

Gareth Roberts

I think Jeff might be a royalty owner or something at Soso; that’s probably why he is asking.

Jeffrey Robertson - Lehman Brothers

In Phase II then, Soso was expected to really be the big production growth this year and then Heidelberg will start to contribute in 2009, is that correct?

Gareth Roberts

I think Eucutta has still got increases as well. I think Eucutta has got steady increases depending upon when we increase the facilities there. We’ve got expansion possibilities on all these fields.

But I think Soso is probably our most consistent performer in the steady production growth that you’ve just seen over the last two quarters. I would just keep projecting that because it’s very, very consistent.

Jeffrey Robertson - Lehman Brothers

Okay, and Phil you said you all sold your Southern Barnett Shale acreage. Can you say again how much you got for that?

Phil Rykhoek

$2.6 million I believe.

Jeffrey Robertson - Lehman Brothers

Okay. Thank you.

Operator

Our next question is from Nicholas Pope - JP Morgan.

Joseph Allman – JP Morgan.

This is actually Joe Allman here. Good morning everybody. In terms of your Selma Chalk play, could you talk about the cost that you are experiencing over there for the horizontal wells and what you’re looking at these days for the reserves per well?

I think you’ve drilled 15 to 20 horizontal wells, what’s been the progression of improvement there?

Ronald T. Evans

On the reserve side, the reserves really haven’t changed much over there. They range on the horizontals upwards to around a Bcf and a half or so. And I think total costs now are up to about $2 million per well. That’s for a 3,000 to 4,000 foot lateral.

Joseph Allman – JP Morgan.

Got you. And have you drilled your 15 to 20 wells pretty much across your acreage positions; have you tested the four corners?

Ronald T. Evans

[East] Heidelberg is pretty well developed. Now we’re just doing in-fill drilling there. West Heidelberg we just have 3 or 4 horizontals over there so that has some running room.

Then the big running room really is in Sharon Field. I don’t know; we’re up to 9 or 10 wells there now I think it is. But we are going to drill probably two thirds of the wells in Heidelberg, East and West, and a third in Sharon.

Joseph Allman – JP Morgan.

Got you. And then what do you see in terms of your unconventional plays; what are you seeing in terms of drilling and completion costs? Some folks are talking about rig rates flattening and other service costs flattening whereas previously they were declining. What are you seeing these days?

Robert Cornelius

I think you are going to see rig rates flatten out as well as service, but the big thing is we’re seeing casing and tubulars, those costs are increasing, so I think you’re going to see an increase....

Gareth Roberts

Net overall an increase?

Robert Cornelius

Yes, net overall an increase, not significant. But you’re going to see a little bit of increase. I just think it has to at $10 an Mcf.

Gareth Roberts

The commodity prices take a while to filter through to the capital costs, but they all do eventually.

Robert Cornelius

Our drilling team and completion teams are trying to get well drills faster and quicker and completed faster. So we’re trying to shave those dollars off through time as well as through watching our costs.

Joseph Allman – JP Morgan.

That’s good. I know this time you didn’t increase your CapEx budget. Are you thinking about doing that if prices stay pretty strong? And then if you did, where would you make some increases in capital?

Gareth Roberts

We have done that for the last couple of years for the same reason that we had cash flow available and we wanted to accelerate some key projects. We haven’t decided yet amongst ourselves where would the key projects would be; it’s a little early to do that. So we’d probably do that towards the end of the second quarter, we’ll probably make some decisions on that.

Joseph Allman – JP Morgan.

Got you, okay, very helpful. Thank you.

Operator

Our next question will come from Michael Scialla - Thomas Weisel Partners.

Michael Scialla - Thomas Weisel Partners

I just want to get an update on the sense of the timing on the 2 wells that you’re drilling at Jackson Dome, when we might hear something on those?

Robert Cornelius

Next call. One of them is a development well on dry ice, and another one is an offset, so those will be next call. Those take almost 6 months between spud to completion.

Michael Scialla - Thomas Weisel Partners

Okay, and then how about the status of the 3D shoot there?

Gareth Roberts

We are still getting permits, but I think we hope to be starting sometime this quarter, don’t we on that?

Robert Cornelius

Yes sir.

Gareth Roberts

So hopefully that will be underway.

Michael Scialla - Thomas Weisel Partners

Okay, and then Bob you had mentioned your capacity was going up to a Bcf a day there. Was that by the end of this year or what was the timing there?

Robert Cornelius

Yes, end of this year.

Michael Scialla - Thomas Weisel Partners

Okay, thank you.

Operator

At this time, we have no questions in the queue. I will now turn the conference over to our host for any closing or additional remarks.

Gareth Roberts

I think that’s all we’ve got today. Thank you everybody, and we will see you next quarter.

Operator

And that does conclude our conference call. Thank you for joining us today.

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Source: Denbury Resources Inc. Q1 2008 Earnings Call Transcript
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