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Denbury Resources Inc. (NYSE:DNR)

Q2 2009 Earnings Call Transcript

August 4, 2009 11:00 am ET

Executives

Phil Rykhoek -- CEO

Mark Allen -- SVP and CFO

Tracy Evans -- President and COO

Bob Cornelius -- SVP, Operations

Analysts

David Kistler – Simmons & Company

Andrew Coleman – UBS

Operator

Good morning, and welcome to the Denbury Resources Incorporated second quarter 2009 earnings results conference call. All participants will be in a listen-only mode. There will be an opportunity for you to ask questions at the end of today’s presentation.

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 forms 10-K and 10-Q.

(Operator instructions) This conference is being recorded. Now, I would like to turn over the conference to Mr. Phil Rykhoek. Sir, you may begin.

Phil Rykhoek

Thank you, Danni. Welcome to Denbury’s second quarter conference call. With me today, I have Tracy Evans, our President and COO; Mark Allen, our Senior VP and CFO; and Bob Cornelius, our Senior VP of Operations.

We reported net loss for accounting purposes, as Mark will further explain, if you adjust for the $194.8 million non-cash mark to market adjustments on a derivative contracts and a nonrecurring $10 million charge related to Gareth’s retirement, our adjusted or clean earnings were $39.7 million or $0.16 per share. Of course, this is less than our net income in 2008 due to the decline in commodity prices, but we are pleased to report that operationally things are generally on track.

A tertiary production continues to grow and we remain on track to achieve our projected 2009 forecast of 24,500 barrels a day, with tertiary production increasing 7% sequentially over last quarter. Bob will give you further detail on our operations in a little bit.

Several other good things have been happening to us at Denbury. This quarter, we completed our sale of 60% of our interest in the Barnett, providing us significant liquidity in the near term and also giving us additional funds to invest in our tertiary program next year. We are still working on our 2010 budget, but we expect it to be somewhere between $600 million and $800 million, probably about $200 million more than our anticipated cash flow as we plan to reinvest the funds we receive from the Barnett Shale.

Tracy would also give you an update on our potential CO2 sources as we’ve had some promising moment in that part of our business recently as we announced. Tracy will also cover the incremental tertiary proved reserves that we booked this quarter.

I guess the biggest negative financial results this quarter is that our hedges are worth a lot less as oil prices improve, causing the mark to market value adjustment, but of course that’s something we don't mind.

So let me turn it over to Mark Allen to give you more details and review the numbers, following Mark, Tracy will review our reserves and the latest regarding our source of CO2, and then Bob will follow with an operational update.

Mark?

Mark Allen

Thank you, Phil. Although we experienced recorded loss of $87.2 million during the second quarter, as consistent with our first quarter loss it was primarily attributable to a loss on the fair value adjustments of our derivative contracts, which was $194.8 million or $120.8 million after-tax in the second quarter. I believe most analysts factor in the cash settlements of our derivative contracts, which equaled $42 million during the second quarter and excluded the fair value changes.

Also impacting our second quarter results was a $10 million compensation charge, $6.2 million after tax, related to Gareth Roberts’ retirement as CEO on June 30. When you remove the charge associated with the fair value changes of our derivative contracts and special compensation charge, our net income would have been approximately $39.7 million or $0.16 per share as compared to $47.6 million or $0.19 per share in the first quarter.

As I will explain in more detail below, the majority of this decrease is due to higher lease operating expenses in the second quarter of 2009. As effectively, there was no change in our oil and natural gas revenues between the quarters if you factor in the derivative settlements, both quarters yielding oil and gas cash inflows of approximately $254 million.

As we have typically done, I will primarily focus on the sequential results of the first and second quarters of 2009, rather than the comparative second quarter of 2008.

During the second quarter of 2009, our tertiary production was in line with our expectations and increased 7% from the first quarter to 24,092 barrels per day. Production from our nontertiary properties was also in line with our expectations for the most part; however, due to the expected decline in our Mississippi nontertiary production and nonrecurring sales of a significant amount of Barnett Shale natural gas liquids during the first quarter of 2009, our overall production decreased 2% between the quarters, resulting in total production of 52,269 BOEs per day in Q2. The incremental Barnett sales in Q1 related to NGLs that we were not able to sell in the third and fourth quarters of last year due to plant shutdowns associated with Hurricane Ike.

As a result of the recent sale of 60% of our interest in the Barnett Shale properties, our estimated average production for the full year 2009 is currently estimated to be 47,500 BOE per day. Our average production in the Barnett Shale in Q2 was 13,390 BOE per day. So you can calculate that our pro forma production adjusted for the Barnett Shale would have been approximately 8,000 BOEs less per day in Q2 or approximately 44,200 BOE per day in total.

As you can surmise from our average production for the first half of the year and our annual estimate of total production and tertiary production, our nontertiary production is expected to decline throughout the remainder of 2009 as we have allocated little or no capital to these properties this year. As mentioned above, our oil and gas revenues for the quarter were virtually the same when you combine our revenues and the cash settlements on our derivative contracts. This was due to the fact that we have approximately 80% of our oil production hedged for 2009 at a floor price of $75 per barrel.

Our average oil price for the quarter, including derivative settlements, was $66.70 per barrel in Q2 as compared to $64.68 per barrel in Q1. But if derivative settlements are excluded, our average oil price for the second quarter was $54.53 per barrel as compared to $39.34 per barrel in Q1. Our NYMEX oil price differential weakened slightly during the second quarter from approximately $3.99 per barrel below NYMEX in Q1 to $5.30 per barrel below NYMEX in Q2. As oil prices have increased during the second quarter, we have seen our differentials return to more historical levels as expected.

Our total corporate lease operating costs increased approximately $8.7 million or 12% from Q1 to Q2, due primarily to incremental expenses related to Cranfield and Heidleberg fields in Q2 as these new tertiary floods move to the production phase and we begin to expense LOE at these fields. In addition, we had incremental expense at Hastings field due to a full quarter’s worth of LOE as compared to two months in Q1. On a per BOE basis, our lease operating costs increased from $15.59 per BOE in Q1 to $17.59 per BOE in Q2. The primary reason being the higher per barrel cost associated with the new tertiary floods mentioned above and higher per unit production costs at Hastings field.

On a pro forma basis, our total lease operating costs would have been approximately $19.90 per barrel if we exclude the interest we sold in the Barnett from our Q2 operating results. Bob is going to discuss our tertiary operating expenses in more detail momentarily.

G&A expenses increased by $10.5 million from Q1 levels, due primarily to the $10 million compensation charge under the Founder's Retirement Agreement with Gareth Roberts related to his retirement as CEO. This compensation consisted of $6.35 million of senior subordinated notes due 2016 and $3.65 million in cash. In addition, we recorded $2.9 million in the current quarter related to incentive compensation awards for the management of Genesis, an increase of approximately $400,000 from Q1.

We do not anticipate that the Barnett Shale will result in lower G&A expense going forward. Therefore, we would anticipate that our G&A rate would increase to the upper $5 per BOE rate for the remainder of the year, due primarily to the lower production going forward.

Interest expense increased sequentially from $12.2 million to $14.9 million, primarily related to higher average debt outstanding during the quarter. Our average debt outstanding in Q2 was approximately $1.36 billion as compared to $1.13 billion in Q1. The higher average debt balance was primarily due to the Hastings acquisition in February 2009 and capital spending in excess of our cash flow through the first six months of this year.

Capitalized interest for the quarter was $15.4 million as compared to $12.4 million in the first quarter. Going forward, we expect our capitalized interest will continue to increase moderately from Q2 depending on timing of capital expenditures and completion of projects.

Our debt at June 30 consist of approximately $951 million of senior subordinated notes and $45 million of bank debt as we have paid down most of our bank debt with the proceeds from the Barnett Shale sale on June 30. For the near-term, we currently expect to have minimal or no bank debt through the remainder of 2009 depending on our level of capital spending each month. This leaves us with substantial liquidity, as we should have most of our $750 million committed bank line available.

DD&A for the oil and gas properties remains relatively flat from Q1 to Q2 on both absolute and per BOE basis despite the significant activity with regard to the booking of reserves and transfer of costs at Cranfield Field and removal of the sold Barnett Shale reserves in net proceeds from our DD&A calculation.

With regard to income taxes, although we do not expect a significant change in our overall tax rate, the mix between current and deferred taxes has changed significantly due in large part to anticipated incremental cash tax of $25 million associated with the sale of our Barnett Shale properties, one of the primary reasons that our adjusted cash flow from operations was lower this quarter.

And with that I will pass it to Tracy.

Tracy Evans

Thanks Mark. As stated in our press release we have booked an additional 10.9 million barrels of tertiary oil reserves at our Phase IV Cranfield during the second quarter. Production continued to increase throughout the quarter averaging estimated 338 barrels per day in the second quarter at Cranfield.

Although the field began to respond in the first quarter, the majority of the oil production at that time was attributed to only one well. Multiple wells began to produce oil in the second quarter and after reviewing the field’s response with DeGolyer and MacNaughton, it was mutually decided the oil response that we had achieved was sufficient to justify the booking of proved reserves.

As being our past practice, the 10.9 million barrels of oil represents approximately a 13% recovery factor of the original oil in place within the patterned area of the field or about 75% of what we ultimately expect to recover. With the response at Heidelberg field during the second quarter as well, we have now achieved a production response at each of our active CO2 enhanced oil recovery projects.

We continue to move forward on the development of additional CO2 reserves at Jackson Dome, as well as our activities associated with the development of anthropogenic sources of CO2. We are continuing down a parallel path on both sources of CO2 as the development of both sources takes considerable time to ultimately develop. The ultimate decision on where CO2 is supplied in the future will be based on the ultimate costs of the CO2 supplied to our actual CO2 enhanced oil recovery projects. In this regard, we have drilled and cased and are in the process of completing an additional well at Glickson Field [ph] within the Jackson Dome area.

We continue to interpret our 3-D seismic data sets and we have acquired additional seismic data in the Jackson Dome area. Although our 2010 capital budget has not yet been finalized we expect to have a much more robust drilling plan in Jackson Dome next year to further delineate, develop, and test additional CO2 potential within the Jackson Dome area.

As we announced in the last several weeks, we have initiated a feasibility study to determine the costs and the most likely pipeline route for a CO2 pipeline to connect potential anthropogenic CO2 sources in the Midwest to our CO2 pipeline infrastructure in the Gulf Coast. We continue to follow the progress of the multiple potential gasification projects that we have current CO2 purchase contracts with, as well as discussing with current emission sources the potential of acquiring their CO2, which is currently being vented.

Three proposed gasification projects, two in the Midwest and one in the Gulf Coast that we currently have contracts with have been notified they are moving forward in the DoE Federal Loan Guarantee Program from the Energy Bill passed in 2005. While this is a significant event for these projects they are still required to finalize negotiations with the Department of Energy, and thus none of these three projects or any of our other contracted projects have begun construction at this time.

Once the feasibility study is complete and if the Midwest project reach the construction stage, we will make a decision on the viability of the proposed CO2 sources in the Midwest. If a decision is made to move to move forward with the development of the Midwest CO2 pipeline, we will examine multiple auctions for financing the pipeline, such as cash flow, bank financing, project financing, third party financing, government financing or accommodations of any of the above.

We continue to have ongoing discussions with various entities in the Gulf Coast region along the Green Pipeline. This includes the proposed gasifications in which we have CO2 purchase contracts, additional proposed gasification plants and other existing sources of CO2. All of the proposed gasification plants have been delayed at least in part due to a lack of functioning credit markets. There are several Department of Energy programs that are in various stages of implementation which are directed at providing funding for CO2 capture projects. The DoE programs are funded in various congressional actions from the Energy Bill in 2005 up until most recently the 2009 stimulus bill. We are working with a number of potential sources which appear to be applying for funding under these programs.

As we have indicated before, it is expensive to separate and capture CO2 from an existing gas stream. And therefore, some of the potential sources of CO2 are not likely to develop without passage of carbon legislation or other incentives. We are working with others that currently emit a nearly pure CO2 stream, we could capture more economically, but these are very small or relatively small volumes and in aggregate are likely less than 150 million cubic feet per day. Bottom line, we are going to pursue all of our options, additional CO2 at Jackson Dome, Midwest gasification plants, Gulf Coast gasification plants, and existing industrial emitters for the CO2 in the Gulf Coast region.

As I stated earlier, we are looking for the most economical source and it looks like we have more than one option to choose from.

And with that I will turn it over to Bob.

Bob Cornelius

Thank you, Tracy. I'll give you guys a quick update of our major projects, production rate, and enhanced oil recovery projects. As mentioned by Mark, Denbury second quarter production averaged 52,269 net BOEs per day and our enhanced oil projects tertiary production averaged 24,092 net BOEs per day during the quarter, 10% increase over the first quarter of 2009.

Production rates from the 11 major tertiary projects remained on forecast for a 12-month average at 24,500 BOEs per day, or 26% increase over the EOR production rate during 2008. We operate five major projects in Phase I area that’s consisting of Little Creek, Mallalieu, Brookhaven, McComb and Smithdale, and Lockhart Crossing. Three of these fields had sequential production increases, those being Brookhaven, McComb, and Lockhart Crossing. Mallalieu’s unit production volumes declined 5% quarter to quarter. A portion of this production shortfall is due to the CO2 recycling facility, which reached its peak throughput capacity.

We have about eight wells with high GORs that are shut-in due limits at this gas separation and CO2 recycling compression. These shut-in wells account for few hundred barrels per day.

In addition, part of the problem is several areas of the Mallalieu unit are experiencing a normal production decline as the unit enters its seventh year of operations. During August, we are planning to expand the recycling facility, increasing the recycle capacity from 160 million cubic feet a day to 230 million cubic feet a day. Although these shut-in wells will be placed back on production, we expect unit production to be flat for the remainder of the year.

Production from McComb Smithdale area did increase 8% sequentially increasing from 2,246 net BOEs per day to 2,429 net BOEs per day. Most of the production increase was achieved without additional capital investment as the team initiated a program to install jet pumps in the producing wells. These jet pumps encourage wells to flow. To date, the production has been successful with over six previously non-responding wells now producing.

Production of Lockhart Crossing also increased during the period, growing 15% or 91 barrels quarter to quarter with several wells responding.

Moving to Phase II which consists of Eucutta, Soso, Martinville, and now Heidelberg, that area increased 300 net BOEs per day during the period. Eucutta’s production improved 9% quarter to quarter increasing 3,813 BOEs to 4,145 net BOEs per day. Now recall, during the first quarter of 2009, work was completed to install Eucutta's recycling capacity and improve that by 100 million cubic feet per day to a total of 180 million cubic feet per day, allowing us to continue expansion in producing these high GOR wells.

At Soso, second quarter production was slightly less than the first quarter because the unit facility was shut in to modify or expand the produced water separation capabilities of the facility. Water treaters, piping, and vessel modifications were all completed during May. This work was completed ahead of schedule and Soso's production rates are forecasted to increase through the remainder of the year.

Heidelberg is our newest and largest Phase II field in terms of reserve potential. We had our first enhanced oil recovery during the second quarter, which was ahead of schedule. And recall that we started injection in Heidelberg during December of 2008. For the second quarter, Heidelberg averaged 250 net BOEs per, and we are expecting further increases at Heidelberg throughout this year.

Tinsley is our Phase III. It's our largest flood to date. Its production increased 1012 net BOEs per day or 42% quarter to quarter. Production increased from an average rate of 2,390 BOEs per day in the first quarter to 3,402 net BOEs per day during the second quarter. Our development plan in 2009 has not been altered and thus we expect continued success at Tinsley Field.

Cranfield is our Phase IV CO2 project. It continued to respond. It increased 194 net BOEs quarter to quarter, more than doubling the rate for the first quarter. Tracy discussed the performance of reserve booking at Cranfield during the second quarter.

Delhi is our Phase V project. It's progressing with well work well underway in the form of drilling, recompletions, re-entries, and reactivations. We are drilling our eighth well of a 12-well program. The Delhi CO2 central facility construction is on schedule with completion expected during the fourth quarter. The 72-mile Delta Pipeline from the Tinsley Field to the Delhi facility is mechanically complete. Pipeline commissioning has been delayed pending final approval of the Department of Transportation. Now we are hopeful that this final approval will come soon, allowing us to commence injection into the field during the fourth quarter of 2009. Our expectations are to see our first enhanced oil production around midyear of 2010.

Tracy mentioned Jackson Dome. On the operations side, the new dehydration facility, the Trace Dehy facility, and several new connecting pipelines are being constructed to loop existing mines and connect new wells. This work will be completed during the fourth quarter. Now today we have the capability of producing and transporting between 900 million to 1 Bcf of CO2.

Also during 2009, we drilled and cased the Kruger Trust [ph] 35-1, as Tracy mentioned, in the Glickson Field; and this well will add further to our production capabilities during the fourth quarter. The potential impact to the CO2 reserves of this well are being evaluated.

Moving to the Green Pipeline, we have over 156 miles of the 320-mile pipeline welded. We have over 152 miles are covered; and we have cleaned, cleared, and restored 135 miles of the right of way. Two major segments or 112 miles of pipeline have been successfully hydro-tested. We started construction during the fourth quarter of 2008 in Louisiana, and today we are welding within 22 miles of the Texas-Louisiana border. We are right now clearing right of way in Texas. Construction is going well. However, our total project costs are now projected to be 8% to 10% over the prior estimated capital investment of $750 million. The majority of these increased costs are related to wet work areas in Louisiana swamps; the increased number of horizontal drills and bores that had to be done, and access delays that occurred mostly during the start-up period. Our timetable has not changed, however, and we expect to complete the Green Pipeline from Donaldsonville, through Oyster Bayou and to East Galveston Bay by the first quarter of 2010 and on to Hastings by year end of 2010.

I mentioned the Green Pipeline [ph] capital costs are better than forecast. However, our total 2009 capital budget projection of $750 million will not be impacted. During the 2009 capital budgeting process, we wanted to ensure capital liquidity, so we held some investment capital in reserve for undesignated projects or over-expenditures. These undesignated funds will be used to cover the increases incurred during pipeline construction, so our 2009 capital budget estimate of $750 will not be changed.

Our teams continue to focus on lease operating expenses, reviewing the CO2 EOR lifting costs. The two biggest drivers in the $0.38 BOE tertiary lifting cost increase from the first quarter to second quarter were lease rentals and the addition of the Cranfield and Heidelberg to the EOR project list. The equipment rental charges are the result of finalizing financing on approximately $21 billion of operating equipment in Brookhaven, Eucutta, Tinsley, and Heidelberg. The addition of the rental equipment added about $1.1 million of operating expenses quarter to quarter, or about $0.30 per BOE increase, accounting for all of the changes quarter to quarter. In addition, we begin expensing the cost of Cranfield and Heidelberg this quarter, further increasing our cost per BOE.

As is always the case, the unit cost of tertiary floods is very high during the initial months of production; and therefore, the addition of two new floods in one quarter made our tertiary operating expense increase. Now if you exclude these two fields, our tertiary operating expenses would be about $19.73 per BOE or a reduction of 4% in LOE when compared to the first quarter. Lastly, the cost of our CO2 increased from $0.14 per Mcf in the first quarter to $0.18 in the second quarter. As you know, the cost of CO2 correlates to the price of oil, which increased in second quarter, since our CO2 production was down slightly, the impact of this increase was not too noticeable, but it is still resulted in a $0.21 increase in our BOE between the two quarters.

In summary, our major tertiary projects are in line with expectations for completion and/or expansion. Production rates are within expectation to follow earlier guidance, and that includes the 20% increase over prior year.

Phil Rykhoek

Thanks, guys. Danni, if we could open it up for question and answer.

Question-and-Answer Session

Operator

(Operator instructions) Now our first question comes from David Kistler of Simmons & Company. Please go ahead.

David Kistler – Simmons & Company

Good morning, guys.

Phil Rykhoek

Good morning.

David Kistler – Simmons & Company

Real quickly, with the tentative 2010 CapEx budget obviously contingent a little bit on commodity prices, can you talk a little bit about what that does for your target tertiary growth in 2010 and maybe '11 and forward?

Phil Rykhoek

Yes, I mean if you recall, of course, 2009, a lot of our money is being spent on pipeline, so we haven't spent too much money really on tertiary projects. Two-thirds of it is going into the Green and Delta Pipeline. Obviously in 2010, that would flip around and most of the money will go into tertiary program and very little for the carry over on the Green Pipeline. We haven't -- we are kind of redoing our models. But also if you recall, that was part of reason, that was part of the reason we wanted to sell the Barnett, was to take that $200 million plus and invest it in our tertiary program in 2010, so that it would help improve our production profile in 2011, which was looking a little bit weak just due to the lack of spending in our tertiary programs. So we think with the Barnett sale and where prices are and so forth, I think we should be well within that 10% to 20% growth per year for the next couple of years all the way up to 2015.

David Kistler – Simmons & Company

Okay. That's helpful. Then kind of thinking about your reserve booking from Crandall [ph], how do I think about -- with the production response at Heidelberg and then potential for Delhi next year, how to think about reserve bookings for balance of this year and potentially next year?

Tracy Evans

Well, as far as the tertiary reserve bookings go, David, the Heidelberg was booked at year-end. So although we've now seen response, there won't be any additional reserves booked at Heidelberg this year. Obviously Cranfield, we've made the initial booking, so it will take some time to see more production history before we could update that one. And then Delhi, with us not starting injections until the fourth quarter and then not having production till probably the later second quarter of 2010, we won't be able to have any bookings at Delhi. So primarily the remaining bookings this year will come from just whatever production -- not responses, but whatever production forecasts we have would indicate increases in reserves out of our existing fields already, maybe Eucutta, possibly Mallalieu and those types, some of the older floods that we originally only booked either the 13% or some number. And now with the production going forward, depending on where it ends up at the end of the year, we may be able to book some reserves there.

David Kistler – Simmons & Company

Potential upticks associated with production response. That's okay. And that was my question with respect to Heidelberg, so that’s helpful. When we think about your feasibility study for the Midwest Pipeline, do you guys have any incremental information or color you could share on that? Timing of when you think you get it back, what kind of impact that might have on the current CO2 agreements you have? Whether or not you're kind of, I guess, forced to take on that CO2 irregardless of what you do on the pipelines, etcetera?

Tracy Evans

Well, the feasibility study right now is scheduled to be released, I believe, this November when we actually get all that back. We're right in the middle of it now. We've done some hydraulics and turning pipe sizes and things like that. But really as far as the final results we're looking at November of later this year. All the contracts in the Midwest are subject, one, having sufficient volume to make the pipeline economic. So obviously until we have this study back it's kind of hard to portray what that looks like. But our ultimate goal is to get the CO2 delivered to our EOR fields at the lowest costs. So we'll continue to evaluate that.

David Kistler – Simmons & Company

Great. That's helpful. I'll let somebody else jump on. Appreciate it, guys.

Tracy Evans

Thanks, David.

Operator

(Operator instructions) We show no further questions, sir. At this time, I would like to hand the call back over to Mr. Rykhoek. Please go ahead.

Phil Rykhoek

Thank you. I guess we have too many conference calls going on at the same time today. Obviously, if you have further questions, feel free to call one of us here. We would be happy to take your questions. Just one last comment, I guess. Looking forward at our calendar, we have a conference presentation next week at the EnerCom conference in Denver on the 12th. While the story remains the same, we plan to have a revised and updated presentation ready for that conference. We're also having a meet and greet mixer at William’s Tavern in Denver after dinner on Tuesday night, the night before, the 11th. And you can come and ask us questions or chat with us. All four of us plan to be there. If you plan on coming, please RSVP to Laurie Burkes, our Investor Relations Manager.

And also just looking further ahead, we plan to have our semiannual fall analysts meeting on November 12 and 12. That will be in Jackson, Mississippi, and I think we plan to go out to Tinsley, to the Tinsley facility. Then we'll follow that up with a summary version of that meeting the following Monday in New York, which again all four of us will be there and probably have some one-on-ones. Okay. He's coming in now? I've just been told we have one more question. Danni, can you get that?

Hello?

Operator

Yes, sir. We did have a question. (Operator instruction) Yes, it just looks like at this time this party has taken themselves out of the queue.

Phil Rykhoek

Okay.

Operator

Okay.

Phil Rykhoek

Well, thank you, everyone. We look forward to talking to you again soon.

Operator

One moment sir, I do have the call back on with the question and that comes from Andrew Coleman of UBS. Please go ahead, sir.

Andrew Coleman – UBS

Sorry, guys, it's just been a nightmare this past hour. There's a whole lot of stuff going on. But the question that I had was kind of thinking about your reserve bookings here. You booked some volumes for Cranfield here in the midyear. Do you think you would have an opportunity to add bookings in any of your other fields, say Tinsley, from performance revisions in the back half of the year? Or are we strictly looking at just 2010 bookings which I think you had mentioned in the release.

Tracy Evans

Andrew, it will all depend on how performance continues to occur later this -- for the remainder of the year. I mean obviously some of the fields -- as we've kind of started this 13% reserve booking several years ago, obviously several fields are getting longer in their lives now. So hopefully performance will allow for some of that. But we don't have any estimates at this time what that number will be. But they would come from some of the older fields, more than likely Eucutta, Heidelberg -- not Heidelberg, sorry. Eucutta or Mallalieu, or one of those. But Tinsley is probably a little bit early yet.

Andrew Coleman – UBS

Okay.

Phil Rykhoek

Did that answer your question, Andrew? He's gone?

Operator

Yes, there's no further questions at this time, sir.

Phil Rykhoek

All right. Thanks, everybody.

Operator

Thank you. This concludes today's conference call. You may now release your line.

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Source: Denbury Resources Inc. Q2 2009 Earnings Call Transcript
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