Denbury Resources Inc. Q2 2008 Earnings Call Transcript

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 |  About: Denbury Resources Inc. (DNR)
by: SA Transcripts

Denbury Resources Inc. (NYSE:DNR)

Q2 2008 Earnings Call

August 5, 2008 11:00 am ET

Executives

Gareth Roberts - President and CEO

Phil Rykhoek - CFO

Bob Cornelius - SVP of Operations

Analysts

David Wheeler - AllianceBernstein

Noel Parks - Ladenburg Thalmann

Mike Scialla - Thomas Weisel Partners

Andrew Coleman - UBS

David Kistler - Simmons & Co.

Scott Hanold - RBC Capital Markets

Anthony Marchese - Monarch Capital

Josh Donfeld - Canyon Capital

Chris Gault - Lehman Brothers

Operator

Good day, everyone and welcome to Denbury Resources 2008 second 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 Forms 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

Thank you, Jason. Welcome everybody, to Denbury's second quarter 2008 conference call. I have with me today Phil Rykhoek, our Chief Financial Officer; Bob Cornelius, our Senior VP of Operations. Tracy Evans, our Senior VP of Reservoir, is not with us today. He has a family emergency, but I will be able to read his reports a little later.

In the second quarter, we earned a record $114.1 million, or $0.47 per share, which includes about $30 million of non-cash losses on the hedges. Our production for the quarter was 46,305 barrels oil per day overall with 18,661 barrels of oil per day from the tertiary oil fields. That was an increase of 9% over the first quarter and an increase of 36% over a year ago.

Taking into account our slow first quarter and fine-tuning the timing on the new floods, we have adjusted our annual forecast to an average of about 20,000 BOEs a day. That's still a 35% increase over the volumes in 2007.

Overall, we have adjusted our forecast to 47,000 barrels a day for the year and that's a 20% increase in volumes over 2007 on an apples-to-apples basis. We still expect continued strong growth for the rest of this year in the tertiary floods and indeed the next several years. The new forecast has now been updated on our corporate presentation and you will be able to the view that today.

We have also seen an initial response from CO2 flooding at Lockhart Crossing and a continuation of a very strong response at Tinsley Field. This response at Tinsley has allowed us to book almost 30 million barrels of new proven reserves at Tinsley. The field is been producing, I think an average of about 675 barrels a day in this second quarter and higher than that today. This is a dramatic illustration of our strategy I think. We expect to duplicate this effort in other fields in the future.

So with that, I would like to turn it over to Phil to give us details of the financial results.

Phil Rykhoek

Thank you, Gareth. I would like to just reiterate, if you look at the earnings, we did have $30.2 million non-cash, fair value adjustment on our derivative contracts and $18.81 after-tax, which equates to about $0.08 per share. So, if you adjust for that, we had clean basic earnings of around $0.55 a share, $0.53 adjusted diluted earnings, which is our highest quarterly earnings in spite of the mark-to-market value adjustments.

As I normally do, I am going to focus on this quarter versus the prior quarter, or Q2 versus Q1. Obviously, commodity prices were the single biggest change, we increased our average net realized per BOE price 28% sequentially from $76.65 in the first quarter of '08 to $98.07 in Q2 on a BOE basis, as both oil and natural gas prices were higher.

Gareth already covered off the production. We did increase 4% sequentially, and of course tertiary was up 9% sequentially, but I won't repeat that. During both 2008 quarters, we did have large mark-to-market value adjustments on the derivatives. We had $38.7 million non-cash in Q1, $30.2 million in Q2 and we have also made significant payments on these derivatives each quarter, $8 million in Q1 and $28.6 million this quarter.

About 42% of the net payments this quarter related to our oil swaps we put in place for a 2006 acquisition and about 58% related to the 2008 natural gas swaps. Of course as of the end of 2008, all our derivatives will be gone.

Our oil NYMEX differentials were at their highest level ever this quarter. We were $9.64 below NYMEX. What's happening is as oil prices have risen, the differentials, particularly in the Barnett Shale liquids and some of our heavier sour crudes, have widened significantly.

Just in looking at forecasting and I would suggest as both estimate or treat the differentials as a percentage rather than an absolute number, because it does seem to increase as prices go up. On the natural gas side, the differentials also increased, although that's largely due to the rise in prices during the quarter and in part due to the sale of Louisiana Natural Gas properties, which tended to receive premium prices due to the location and their btu content.

Our operating costs increased 16%, sequentially on a gross basis, 13% sequentially on a BOE basis, $16.15 per BOE in the first quarter to $18.23 per BOE this quarter. A significant portion of this increase relates to the cost of our CO2 that is injected. During Q1, we averaged $0.22 per Mcf for our CO2 cost, but this jumped to $0.27 per Mcf, a 23% increase.

As we have discussed, the biggest component of the cost of CO2 is the oil price. It correlates directly and the percentage increase in our CO2 cost is about the same as the increase in the oil price. Since our tertiary operating costs are now more than 50% of our total operating expenses and since the cost of CO2 and power and fuel are over half of those expenses, you can expect our operating costs to have a high degree of correlation to commodity prices.

If you remember on the first call, we discussed a change in our accounting, wherein we begin capitalizing injection costs in 2008 until we see an initial tertiary production response. In Q1 of '08, this amounted to $2.9 million, but this quarter we only capitalized $1.4 million, approximately one-half, as we begin to expense the injection costs at Tinsley Field following our initial production there in April of '08. On a quarter-to-quarter comparison, this accounted for about $0.30 per BOE of the increase.

Looking forward, if prices continue to stay high, we would expect our operating costs to remain in this $18 range most of the year. That's higher than our prior guidance, but largely due to the anticipated higher oil prices.

D&A came in $1.2 million lower sequentially, about as expected as our first quarter is usually higher due to significant year-end costs. We are continuing to expand and grow, having increased our employee headcount by 11% year-to-date in 2008, and the retention of personnel and hiring new people to accommodate our growth is a significant focus. We are seeing wage inflation continuing in our industry, so, looking forward, we don't expect G&A to come down. In fact, it probably will gradually creep up.

As of quarter end, we had $525 million of total debt outstanding. That's excluding the capital and financing leases with Genesis, all of which was subordinated debt. We did not have any bank debt and we had over $150 million of excess cash, which was generated by the drop downs with Genesis completed in late May.

With the drop in commodity prices just in the last few weeks, our projected cash flow has been reduced a little bit, but we still anticipate that the combination of our cash on hand and projected cash flow will be more than enough to fund our revised $1 billion capital budget. Also keep in mind; we have a totally undrawn bank credit line. Of course, if we were to do significant acquisitions, that would require additional capital.

Looking at DD&A, DD&A increased 5% sequentially from $11 per BOE in Q1 to $11.53 per BOE this quarter. With the production response at Tinsley, we did book roughly 30 million barrels. However, along with these incremental proved reserves, we transferred approximately $195 million from unevaluated properties to the full cost pool. That represents a portion of the acquisition cost of that field and other expenditures incurred there to-date. These costs coupled with the remaining future development costs brought these Tinsley reserves at an average cost of just over $12 per barrel. Therefore, the incremental reserves did not help our DD&A rate.

Note that this is only about 75% of the reserves we expect to recover at that field, but that we are basically burdening that field with 100% of the cost. Assuming we recognize the remaining 25% that we ultimately expect, our average cost per barrel should get down into single digits at Tinsley. I should also mention that booking an approximately 75% is consistent with how we recorded initial proved reserves at most of our new fields. This quarter we also had an extra $37 million of incremental costs that we put into the full cost pool following our decision to discontinue our leasing programs, which also contributed to the incremental higher DD&A rate.

Which leads me to income taxes, we recently obtained approval from the IRS to change our method of accounting for CO2 transportation and injection field assets used in our tertiary operations. Previously we capitalized and depreciated these costs. We have obtained approval to deduct these costs once the assets are placed into service. The net effect of this change gets rather complicated, but bottom line we expect a refund of approximately $6 million reflecting the impact of the change through 12/31/07. We have preliminarily increased our tax credits by approximately $37 million through that same period.

Further, for the balance of 2008, while the total tax rate will remain around 38%, instead of projecting about one-half of that provision to be current, we now expect that percentage to be reduced to approximately one-third of the total tax provision. Bottom line, we expect this tax accounting change to save us between $40 million and $50 million of cash income taxes for 2008. Because this tax accounting change accelerates certain tax deductions with resulting lower cash taxes, the change impacts certain types of financing type transactions we have historically used.

We have highlighted two of these in our press release, the discontinuance of our operating lease program and the possible impact on certain types of transactions with Genesis. The discontinuance of the operating lease programs is a primary reason for the increase in our capital budget from $900 million to $1 billion, as we previously had contemplated leasing about $78 million of equipment during 2008. To-date we have leased approximately $105 million of equipment and we had another $100 million scheduled in '08 and '09. Discontinuance of this program will increase our capital budget short term, but long-term it will save us on these operating expenses.

As to Genesis, since the tax accounting change will allow us to deduct the cost of CO2 pipelines once they are placed in services, it changes the economics of Genesis drop downs for those transactions that are sales for tax purposes, such as the recent $75 million sale and associated long-term transportation service agreement on the Free State Pipeline. Therefore, these types of transactions are likely to be discontinued. However, this tax change will not affect transactions that are not sales for tax purposes, such as the recent $175 million financing lease transaction recently completed on NEJD pipeline, provided these transactions meet other necessary tax criteria. Plus, we are looking at other options and ways that we can use Genesis as a financing vehicle for Denbury with other assets.

With that, I will turn it back to Gareth.

Gareth Roberts

Thanks, Phil. Good news on the tax refund. Tracy, as I mentioned, is not able to be with us, but he has given me a report on the reserves. As you may know, we don't actually release mid-year reserves, so what we are going to do is give you an update on the significant changes since year end. The vast majority of those increases are in three areas, the Barnett Shale, Selma Chalk, and the CO2 response at Tinsley Field.

As we announced in the press release, our single largest reserve addition since year end is the 29.8 million barrels of oil, as a result of achieving initial response to the CO2 injections at Tinsley. The initial CO2 reserve book at Tinsley represents approximately a 13% recovery factor, or approximately 75% of the total estimated CO2 reserves that we ultimately believe will be recovered from the Woodruff Formation.

So, there is more to come we believe. Due to the magnitude of the Tinsley CO2 oil reserves, DeGolyer and McNaughton was requested to review an estimate the initial proved reserves CO2 bookings for Tinsley Field and concurs with our estimates. The timing of the recognition of the additional CO2 reserves that we believe will be recovered from the Woodruff Formation at Tinsley will depend upon the flood performance demonstrating the ability to recover the additional volumes. The D&M initial reserve estimate is similar to the way that D&M originally estimated the CO2 oil reserves at Eucutta Field.

As additional development drilling occurs, additional drilling locations, one offset why it has become proved at undeveloped locations. Since year end 2007, we have added approximately 41.2 MMcfe or 6.9 million barrels of reserves equivalent in the Barnett Shale and Selma Chalk, primarily from adding these additional proved undeveloped locations. We have not had any significant net revisions for those since year end, although reserves would obviously decrease as a result of production. Plus we did complete our sale of Louisiana properties in February lowering our proved reserves by approximately 1.6 million barrels of oil equivalent.

Looking forward to the rest of the year, we are expecting to add additional proved reserves at Lockhart Crossing field based on the initial oil response to CO2 injections there, and additional reserves in the Barnett and Selma Chalk based on the development drilling that we are doing there. We have also begun CO2 injections at Cranfield Field, though it's uncertain whether or not we will see the initial oil response in time to book reserves by year-end. So, we don't really know where we are going to be on that exactly by year-end.

With that, I would like to pass it back to Bob Cornelius to give us an update on the operations.

Bob Cornelius

Thank you, Gareth. I will give you an update on several of our major projects. As of first, I will get in touch on second-quarter production. During the second quarter, production averaged 46,305 BOEs per day. That's a 25% increase over 2007 production after adjusting for the Louisiana property sale. Enhanced oil recovery projects in the Barnett Shale were the drivers to these increases. Quarter-to-quarter the CO2-enhanced oil project showed an increase of 1,505 net BOEs while the Barnett Shale had an increase of approximately 633 net BOEs.

The majority of the enhanced oil recoveries posted was from the Tinsley. Tinsley is our newest and largest EOR project. Soso and Eucutta, both Phase II projects, posted nice quarterly gains also. I am pleased to report that all of our EOR projects experienced second quarter increases over the first, with the exception of Little Creek, which is a very mature field and Martinville, which is our smallest EOR project.

Those that follow Denbury closely know that Tinsley is our largest enhanced oil recovery field in terms of both reserves and future growth potential. CO2 injection began in Tinsley about 18 months ago at a very reduced rate. First enhanced oil sales were posted and reported during April 2008 and now with 20 producers, our average rate is continually climbing significantly over the first-quarter rate of 635 net BOEs per day.

With a 24-inch CO2 pipeline in full operation and commissioning of the Tinsley facility, we are now injecting approximately 120 million cubic feet into 10 injection wells. We also are completing the first expansion of Tinsley to recycling and production facilities to develop more injection patterns, increase injection rates, and CO2 recycle capabilities. Eight injection wells will be added during the third and fourth quarters to support future production from this large field. We are expecting some really great things out of Tinsley.

Soso and Eucutta, both Phase II projects, experienced second quarter production increases of 27% and 9%, respectively, over the first quarter. Soso averaged 1,885 net BOEs during the second quarter and continues to increase nicely with the addition of two producers and three injections during the quarter. This is the sixth straight month that Soso had still experienced a production increase. A team is working to increase injection rates and have completed an 80 million a day facility expansion project to be ready for this additional growth. As reservoir performance and current injection and production withdrawal rates indicate, Soso should continue to perform as forecasted.

Eucutta continues to be one of the best performing fields. Since its first production during November of 2006, the field has increased production quarter-to-quarter. Average production this quarter was 2,933 BOEs per day compared to 2,699 net barrels during the first quarter. Now, the team is completing their development efforts in Fault Block Three on the west side of the unit, and the expansion of the recycle facilities from 80 million a day to a 100 million a day later this year. Completion of these two events will be a mechanism for improved oil recovery into the end of the year.

Of the four major producing fields in Phase 1, McComb and Smithdale exhibited significant improvements during the second quarter. McComb and Smithdale showed a nice 11% increase when compared to first quarter to the second quarter. We average 1,818 net BOEs in the second quarter. This increase was helped by the re-drill of the Smithdale 20-8 No 1. The 20-8 No 1 was lost due to mechanical problems during late November of last year. The team also improved CO2 injection profiles and injection rates in McComb plus the completion of additional key wells should assist in future production increases from McComb and Smithdale.

Mallalieu is located in southwest Mississippi and it is the largest producer of all the CO2 fields. Its production averaged 6,260 net BOEs per day during the second quarter. Mallalieu's rate is expected to be relatively flat for the remainder of the year. Our geological team and reservoir teams and operation teams continue to investigate alternatives to injecting the various production stands in the West and East Mallalieu units.

Denbury's newest success in Phase I is Lockhart Crossing, near Baton Rouge, Louisiana. CO2 injection began there December 7, 2007, and when, and we had our first enhanced oil production was majored in late June and the first sale was in July. Although it is very early in the process at Lockhart, the unit continues to [sell] continue rate increases on a weekly basis. Today we have five injection wells and six producing wells. Total rate is slightly above 200 net BOEs per day. We have a drilling rig working in the field. We will add three additional wells during the third quarter.

Gareth mentioned Cranfield. Cranfield is our first Phase IV field. It is located in western Mississippi, and it began injection in the second week of July 2008. We now have five injection wells placing over 20 million cubic feet a day into the reservoir. Our plans are to continue to add four additional injection wells during the third quarter and increase injection rates to approximately 40 million a day soon.

As Gareth reported, we hope to produce our first enhanced recoil production by the end of the year. We are really looking towards the first quarter 2009 to have that in production. As you know, securing enough CO2 is probably our most important part of our strategy. In Jackson Dome, our CO2 source now produces in excess of 600 million cubic feet a day. That's an increase of 8% quarter-to-quarter.

Even with this record rate, we continue to invest capital to improve our production as well as dehydration and transportation capabilities. The drilling and completion of four high rate CO2 wells with the capacity to produce anywhere between 50 million and 100 million cubic feet per day each has added to our capability of production from 300 million to 400 million cubic feet a day. We also commissioned the second Barksdale dehydration facility, which added about 300 million cubic feet of processing capability. We also completed the Brandon pump station, which will allow us transport an additional 125 million a day to various pipelines on our system.

With the completion of our 2008 drilling program, and these other facilities that we have done, we will have deliverability in excess of 800 Mcf or maybe even 850 Mcf, million cubic feet a day by the end of this year. The team is consistently working to maintain our CO2 supplies capacity. We want to stay ahead of our tertiary floods and any possible acquisitions we make. Our goal is to have the capability to produce in excess of a Bcf per day during early 2009.

Finally, let me conclude with the Barnett Shale operations. Our Barnett Shale team continues to exceed production forecasts and expected results. As discussed in prior releases, the team continues to improve overall drilling and connection time. Our drilling time that now averages 19 days from spud to release. That's a 5% increase over last year. But more significantly, our production rate from spud to first production now averages 50 days. That's 20% less time than 2007. The team is also now reviewing methods and making changes to improve our infrastructure and compression capabilities. That's going to help optimize both new completions and existing wells as we go forward.

As Gareth pointed out, even with the successes that we have had in the second quarter; the company reevaluated our production forecast. We assessed current production rates, analyzed and included the lower first quarter production levels, past reservoir performances, and planned facility expansion.

Based on these analyses, we lowered anticipated tertiary production to an average of 20,000 BOEs per day for an average for 2008. It should be noted that 20,000 BOEs per day is a significant 35% increase over 2007 average production rates of 14,765 net BOE. Correspondingly, the company also made production for 2008 average from 49,000 BOEs per day to 47,000 BOEs per day is our new forecast. These revised rates represent a 20% organic rate over 2007, adjusted for the Louisiana sale.

So back to you, Gareth.

Gareth Roberts

Thanks Bob. Well, obviously we didn't like to have to reduce our forecast, but on the other hand, we like to be able to meet or beat our forecast. So, it became necessary to make the change. As Bob has pointed out, there is still very strong growth there. So, I hope perhaps we have been a little conservative with this, but we think it's the right way to do it.

Overall, the company has never been in a stronger position than it is today, both operationally and financially and I don't think we have ever had really a better outlook. One of the important things that we are going to be able to do is achieve this growth through cash flow, which means we're not needing to issue further equity to take this plan forward, and I think that's something that the market is overlooking. I'd also like to point out that we have no exposure to subprime loans either, although you wouldn't know that from looking at the market.

With that, Jason, I would like you to come back online and take some questions.

Question-and-Answer Session

Operator

(Operator Instructions)

First question is from David Wheeler with AllianceBernstein.

David Wheeler - AllianceBernstein

Good morning.

Gareth Roberts

Good morning.

Gareth Roberts

Gareth, you mentioned in the press release that you guys had reviewed and revised the tertiary production model. Can you talk to us a little bit about the changes that you made there? It seems like the timing of ramp up to peak production on different phases has been pushed out one to two years, but that the rates haven't changed. Are there any impacts on ultimate production and reserves from the EOR field?

Gareth Roberts

No, there is no impact on reserves. It's simply a timing issue, that's all we have really done is just change the timing. We talked in the first quarter about specific delays and so forth, and we don't really want to talk about that sort of thing anymore. I think what we have done is try to build in a reasonable timing to all of these future activities. We are looking out several years in our forecast that you are looking at, and we are trying to guess when we are going to be able to complete certain pipelines and things like that. So, we've tried to build in more of a cushion for the types of delays that we've seen on historical projects.

David Wheeler - AllianceBernstein

It sounds like this above ground, its sounds like below ground are the reservoirs performing as expected?

Gareth Roberts

Below ground, the reservoirs are doing much better than Wall Street.

David Wheeler - AllianceBernstein

Is there any change in the ratio of CO2 that you need to get out a barrel of oil?

Gareth Roberts

No, all of those things have not changed. Let say, we have had some delays and I think we have also been getting better at forecasting it. And as I said, I hope that we're being too conservative here, but these growth rates are still very strong.

David Wheeler - AllianceBernstein

Okay, great. I had a couple of other questions for you. Faustina was expected to get financing in the current quarter, third quarter. Do we know the status of that? And are they going ahead with construction at year end?

Gareth Roberts

They haven't started this right now. And I think, if Tracy was here he would be able to give us an exact answer, but we think it's being pushed back. Maybe to quarter one, I think, is probably the timing on that.

Bob Cornelius

It was first quarter '09.

Gareth Roberts

First quarter, we will have to double check that though and make sure that that's there.

David Wheeler - AllianceBernstein

Have you guys gotten bids in for the Green Line at this stage?

Gareth Roberts

Yes.

Phil Rykhoesk

Yes. The Green Lines, we've got our construction bids in and we're finalizing those contracts right now. Very fortunate to have to work with contractors, each specializing in the area that they are playing in, whether it be marsh or dry land or across (inaudible). So we have got those in, we should lock those in.

The pipeline is being rolled right now, the pipe itself. We are very fortunate to lock in our prices. We don't see any large price increases there and we are working on right-of-ways right now. We have over 31% of virgin right-of-way in Louisiana and working towards 10% in Texas. So, that project now [hope to be on forecast].

David Wheeler - AllianceBernstein

Okay, good. The change in the tax treatment that Phil mentioned, does that impact your ability to do drop downs of the Green Line in order to finance that, ultimately?

Phil Rykhoek

Well, it depends on the type of drop down that you do. We had two different tax structures in the Free State and NEJD. NEJD was effectively a financing lease, so that didn't count as a sale for tax purposes., Actually if you look at that the reason was we had a very low tax basis in NEJD, because we purchased it very cheaply. So yes potential, we can still do drop downs, but they would have to be financing leases and not sales for tax purposes.

David Wheeler - AllianceBernstein

Okay. What does that mean to you in terms of how attractive it is to do drop downs and the proceeds that you might get from drop downs?

Phil Rykhoek

Well, it's still attractive. There are some other tax criteria that we have to meet with Genesis, so we can't do unlimited financing leases with them. But no, it doesn't affect our economics or attractiveness to Denbury.

Gareth Roberts

I think the major point is that when that pipeline is placed in service, there is $700 million that can be written-off against taxes, against current taxes, and we are a current taxpayer, increasingly so, obviously because of higher oil prices. We project based on increased production and reasonably high prices in the future that would continue. So, it's a major event for us to be able to write that off.

David Wheeler - AllianceBernstein

Okay, for example in your PV-10 at the end of '07, do you have that? Were you anticipating to be able to defer the taxes associated with the Green Line CapEx or is that or are you going to perhaps have an enhanced PV-10 because of being able to defer taxes?

Gareth Roberts

None of our PV-10s actually take into account tax positions. I think they are all pre-tax, aren't they? If you are talking that the FAS 69 disclosure, there is taxes built in that, so, yes, that may help PV-10 a little bit because it would be pushed out. The PV-10 reserves per se don’t take that into account.

Phil Rykhoek

It's a cash timing issue, really. We get the cash up front. We get to reinvest the cash and we don't have to borrow money. So right now '09 is looking very healthy because we have got a strong cash flow. We think we are going to easily cover off the CapEx that we anticipate right now. So we think we are going to exit '09 in a similar sort of position as we are right now.

David Wheeler - AllianceBernstein

Okay, great. Thanks very much.

Gareth Roberts

Thank you

Operator

We'll go next to Noel Parks with Ladenburg Thalmann. Just one moment. Hey Mr. Parks your line is open.

Noel Parks - Ladenburg Thalmann

Good morning.

Gareth Roberts

Good morning.

Noel Parks - Ladenburg Thalmann

Just a few questions about Tinsley, I was interested in hearing a little more detail on the various phases within larger Tinsley projects, and where you stand now. There was a discussion of some additional injectors on the way. So could you just maybe give a little more detail on that?

Gareth Roberts

We don't sort of give day-to-day updates on this stuff, because otherwise we wouldn't be able to stay away from the telephone. So what we have really done is just given you the sort of second quarter average numbers on production. But, clearly, we are continuously increasing the injection.

We are continuously increasing the pump capacity and the production thus far, has also shown a continuous increase. We think that this is going to look very good at the end of the third quarter we should have some very good numbers to report. But we don't really go into sort of day-to-day numbers.

Noel Parks - Ladenburg Thalmann

Sure. I'm thinking back about maybe about a year or so to one of your past presentations where, if I remember, there is a part of the field where the development and the injection began last year, a large part that was going to start this year. If I remember sort off to the north section was going to be the furthest out?

Gareth Roberts

Yes. There are various phases, one is up in, what we call the sort of the gravity drainage areas what we call it. But that's area is receiving CO2 and has been for since the beginning of the year on large volumes and pressure. That part of the reservoir has to pressurize up, so that is why we are not getting any oil production from it. But once the reservoir pressure is up, we expect very strong production response from it. In fact it should be very, very good part of the flood, but that's still pressuring up.

Noel Parks - Ladenburg Thalmann

Okay, but overall has maybe the furthest or the latest phases of Tinsley, have those been pushed out by, would you say, maybe a couple quarters or --

Gareth Roberts

Tinsley, we forecast that one because it's the newest field really. We forecast that later. We were a bit more conservative, perhaps the way we forecast that anyway. So I really don't think we changed Tinsley hardly at all in this quarter. So it is a field-by-field reevaluation that we did. Tinsley I don't think has been affected by the re-forecast.

Noel Parks - Ladenburg Thalmann

Okay, great. That's just what I was looking for. A question, this may be for Bob, when you were talking a little bit about trying to have more cushion in the CO2 uplift timing, you are assuming looking forward especially into the out years. Are the factors that you are considering mostly people issues or crew issues, supplier issues, a combination?

Bob Cornelius

No, what we are trying to do is we are trying to stay ahead. The first thing we have to do is drill a well. So we are ahead, we are on schedule with our drilling program. We plan to complete and continue to drill rigs exploring for and looking for additional CO2 volumes. So that is in progress.

The second thing we have to do is we have to put the pipe in the right place. Those pipes we have got scheduled for the first half of next year. And that's going to be a lot of work in the Dome to add some stuff. And the third thing we have to do is we have to put dehydration facilities in. We had planned to build a dehydration facility for next year. So by doing those three things all of them have to be done on time which we have them all scheduled. We should have that, we should stay ahead of our requirements for the next two, three years.

Noel Parks - Ladenburg Thalmann

And when will, I think you said at Barksdale, that dehydration facility be done?

Gareth Roberts

The Barksdale facility.

Bob Cornelius

Barksdale one and two are both on and online. We have close to 600 million cubic feet a day dehydration.

Gareth Roberts

We just completed Barksdale two.

Bob Cornelius

The second dehydration facility we just completed about two months ago.

Noel Parks - Ladenburg Thalmann

Okay, great. That's all from me, thanks.

Operator

Thank you. We'll go next to Mike Scialla with Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Good morning, guys.

Gareth Roberts

Good morning.

Mike Scialla - Thomas Weisel Partners

I apologize if you already answered any of these. I missed the first part of your call. But with Mallalieu now projected to be flat, how does that compare to your original projection?

Bob Cornelius

We at Mallalieu, had a slight increase throughout the year, so we flattened that increase. And that's part of why we have moved our forecast downwards slightly.

Mike Scialla - Thomas Weisel Partners

Was that based on performance or timing, or what was the issue there?

Gareth Roberts

Well I think it's both. Plus I think there are physical limitations on the facility that we are running into. If you remember, this was originally a pilot unit that we have continually expanded. We are running into some structural issues of increasing the field beyond a certain point. So, we are going to have to make some changes if we want the field to produce significantly more, and I think those are in the budget for later this year and next year.

Mike Scialla - Thomas Weisel Partners

Okay. Then, in Jackson Dome, I think, last quarter you talked about getting to a Bcf a day, hopefully by the end of the year. It sounds like that's been pushed out. Is that a performance issue or is that timing primarily?

Gareth Roberts

I don't really think that's been pushed out. I thought we were ahead of forecast on the availability of CO2. I think the delay issues have been things like adding that booster station to the Jackson Dome pipeline. It's not been the availability of CO2 at the Dome itself; that has to been on schedule.

Bob Cornelius

That's correct. We are drilling some exploratory well or we have an exploratory well now and the well looks like it should come in on time and where it should, but we kind of hedge our bets. If that well comes in, we will probably have that capability first quarter. So, that answers that and then like I said the facilities are in line and in place.

Gareth Roberts

I know the minor issue in changing timing has been for example on the delta pipeline to Delhi field, we've been waiting on getting a permit from the core of engineers across the Mississippi and that's being slow. So we've adjusted the timing on that for that.

Mike Scialla - Thomas Weisel Partners

Okay. That exploratory well you mentioned at Jackson Dome is that the offset to dry ice field?

Gareth Roberts

No, it's not an offset to anything. It's a completely standalone well.

Mike Scialla - Thomas Weisel Partners

And what kind of target size are you looking for there?

Gareth Roberts

It's a fairly big step out well. It could have a very wide range, anywhere from 200 Bcf to 2 Tcf, I mean just can't tell.

Mike Scialla - Thomas Weisel Partners

Okay. So, that could be very significant.

Gareth Roberts

It could be significant. Probably we're using some smaller numbers obviously in our probable.

Mike Scialla - Thomas Weisel Partners

Okay.

Phil Rykhoek

One more comment on, we have, to just let you know we put out and we do a nomination process with every one of our fields and every one of reservoirs, so we know how much CO2 to anticipate on a monthly basis and we have that out overview. And right now, we're looking at in here 750 million cubic feet a day as max.

Gareth Roberts

What we need to use.

Phil Rykhoek

What we need to use and inject in to our existing reservoirs. So, the point is we're staying 200 million cubic feet ahead of our schedule injections.

Mike Scialla - Thomas Weisel Partners

Right, now I understand that, I thought, I could be incorrect. I thought on the last call you might have been targeting a Bcf a day of capacity by the end of the year. But it sounds like you are going to get there either way. In terms of acquisition with your balance sheet as strong as it is now, how large your acquisition would it be (inaudible) to entertain before you'd have to think about raising additional capital and what does the market look like there now?

Bob Cornelius

Market is looking a little better. Oil price is coming down a bit, helps us in that regard. And we're looking at a whole range of sizes. There are small deals out there and there is some pretty big ones too. So, we're pretty optimistic that we're going to sometime before the end of the year; we are going to be able to pick up some nice additions.

Mike Scialla - Thomas Weisel Partners

Do you think anything out there would necessitate additional capital or can you handle it with your balance sheet, the way it is now?

Bob Cornelius

We can handle it with our balance sheet.

Mike Scialla - Thomas Weisel Partners

Great. That's all for me. Thanks.

Bob Cornelius

Thanks.

Operator

We'll go next to Andrew Coleman with UBS.

Andrew Coleman - UBS

Good morning everyone.

Gareth Roberts

Good morning.

Andrew Coleman - UBS

I had a couple of quick questions here, looking at your deferred tax, when I look at it going forward how long do you think it's fair that, you will have an elevated deferred tax rate? Kind of couple years, as the pipeline expenditures kind of finish up or you think it will be a more of a continuous event?

Phil Rykhoek

Well, at least yeah, and lot of it is, it will be very strong in next two or three years because of the pipeline. I mean, of course that's all you know, you look at our expenditure graph on the internet, the expenditures drop-off from like 2011. As Gareth said, we hope to buy things by then. So, it all depends on our spending patterns. But the good news is we can write these things off, so it's going to help our cash taxes at least as long as we are spending money.

Gareth Roberts

I imagine it's not just pipelines either. It's anything to do with obtaining the CO2 stream off the facilities and other bits and pieces, which is why we discontinued the financing of the facilities.

Andrew Coleman - UBS

Okay. Looking at the Barnett, have you guys been seeing any constraints there on a liquids handling capacity?

Bob Cornelius

No. No, we have not. We have not had any kind of curtailment.

Andrew Coleman - UBS

Okay, great. Then kind of jumping around here to look at reserves for a second, with Tinsley booking 30 million barrels, probably I guess the other 10 million will come in some time next year or the year after. What other kind of big, blocky pieces might go in there to help you fill out your reserve profile?

Gareth Roberts

We mentioned Lockhart and Cranfield. Another big kahuna is Heidelberg, which is something we will have to discuss at year end. It could well be under consideration at year end.

Andrew Coleman - UBS

Okay. And do you think then that the combination of those will kind of keep your F&D costs kind of flattish for the year?

Gareth Roberts

Yes, the short answer is yes.

Andrew Coleman - UBS

Okay.

Gareth Roberts

We expect to maintain, just depending on the timing, exactly. But overall, yes, we expect over the next certainly over the next two or three years to be booking significant volumes of reserves as these big floods start to come on. So the big floods I define as Tinsley, Heidelberg, Delhi, Hastings. These are fields that have made hundreds of millions of barrels, and there is very significant reserve adds to be gotten from them. So we would expect those to come in, while Hastings would be the last one depending on the timing of when CO2 flooding starts there. But we expect that to be a feature of our company over the next few years.

Andrew Coleman - UBS

Okay, great. Then my last question is, looking at the Mississippi non-CO2 volume. Can you give any color or how you expect that to progress through the end of this year?

Gareth Roberts

I think we have a very slight decline, flat to very slight decline.

Andrew Coleman - UBS

Okay, thank you.

Operator

We will go next to David Kistler with Simmons & Co.

David Kistler - Simmons & Co.

Good morning, guys.

Gareth Roberts

Good morning.

David Kistler - Simmons & Co.

Quick question for you, when you mention acquisitions in response to a question earlier, what about just buying your own shares given the recent pullback?

Gareth Roberts

Well, if they get cheap enough, we might have to consider it. Obviously, it hasn't been part of our game plan up until this point because we have some great things to invest in. But I do think that the market severely overreacted and not just to our production forecasts. I think it was doing it before. And so we will have to take a look at that.

David Kistler - Simmons & Co.

Okay. And then switching over to, in the past, you guys have had some issues with compressors. As you kind of continue your expansion and as you build out towards peak production, pushing that out a little bit. Can you talk a little bit about how you are pre-ordering compressors? What kind of redundancies you are doing there? And then also what's happening to costs from that standpoint?

Bob Cornelius

On our compressors, we have had an alliance with our supplier, so we are now ordering compressors 18 months out. So we have that situation under control. We also saw some recycle capacity, like Gareth mentioned at Mallalieu. So we are re-examining that's one of the things we did in the forecasting, so, we are now placing orders for those compressors to handle the increased recycle capacity we might have in some of these floods like Eucutta, like Tinsley. So those are already in place and on order.

As far as redundancy, you have to look at redundancy too. Each one of these units, again it's pretty much on the same frame. So when we have a problem, we can take one unit and move it to another location or if a flood needs it and requires it and we have one on it we can move that into that flood that needs it. So those things I think now are in place and moving forward as they should.

David Kistler - Simmons & Co.

Okay. Switching to increasing the employee base by about 11%, can you talk about where employees were added specifically and how we should be thinking about that going forward as well?

Gareth Roberts

A lot of them are at the field level. That's the largest single area. Then we have an ongoing need for technical staff as well, and that's been challenged over the last couple of years and continues to be and we expect that to be possibly even tougher going forward. But that's not unique to our company, that's something that affects all of the oil and gas companies.

David Kistler - Simmons & Co.

Sure. Then just two last housekeeping questions. You performed a 3-D shoot on Jackson Dome. Can you talk a little bit about where that is right now, what you are seeing on that? Has that changed your viewpoints at all?

Gareth Roberts

I think we have just completed the actual shooting, so we have not looked at any data yet.

David Kistler - Simmons & Co.

Okay, then last housekeeping, kind of thinking about the potential anthropogenic sources of CO2, Faustina you already covered. Can you talk a little bit about the Rentech agreement or any other agreements you are looking at so we can be thinking about additional CO2?

Gareth Roberts

We have had contact with several different potential sources, new sources, and we have executed some contracts with those. So we haven't given an update as yet and we are considering doing that sometime in the next couple of months. So, just stay tuned there and we will try and give an update. Obviously, we think that this is a very, very important part of our business. And so, we do want to give the market a heads-up on how well it's going. And obviously, we think that come the new administration in this country that we will see some form of carbon ceiling, carbon tax, carbon credit, whatever you want to call it, is probably going to come into play, which is going to I think highlight our situation.

David Kistler - Simmons & Co

Okay. Well, I thank you guys very much for the additional color.

Gareth Roberts

Thanks.

Operator

(Operator Instructions)

We'll go next to Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Good morning.

Gareth Roberts

Good morning, Scott.

Scott Hanold - RBC Capital Markets

Not to beat a dead horse, but looking at the adjusted long-term outlook for tertiary oil production. Can you kind of give a sense and I know if we kind of go back a couple years, I know you reset the bar and it was I think more of a logistical issue at that point. But can you talk about the challenges and the cushion you built-in for variability of the different reservoirs in each of these phases?

Gareth Roberts

That's the single most important thing that we've done is, we've delayed the response time on some of the later phases within an individual field. And this is because we have had more experience now with these older patents. Then what we have found is that we get to response as we projected in some of the wells and then there is always a few wells in each patent that seem to respond slower, so that the average of a phase that's been around for two or three years is a little bit less than certainly the initial response average.

So that's something we have only just learnt, because we have only just been doing these sort of patents for last two or three years. So, I think we delayed some of the response and that's been the major change. We just extended it out, so that the reserves don't change. It's just a timing issue.

Scott Hanold - RBC Capital Markets

Right, so just to understand it, so part of it was taking a look at the existing floods that have been online a lot longer and recognizing that as you get beyond the first several years that recovery starts to slow relative to what you had previously predicted?

Gareth Roberts

Yes, it just takes a little bit longer to get the sweep through, but it doesn't affect the total reserves. In fact, because the higher oil prices, we actually expect to stay in these patents, ultimately, a lot longer than it would even be projected.

Scott Hanold - RBC Capital Markets

Okay. Obviously high oil price is a good thing, but is that also built into the model with, if we continue to have $100 to call it a $150 oil prices, that you will be running these phases longer and they will be much more mature. But then, there is sort of how do you allocate the CO2 to a new project that may need it, while you are still injecting it into an existing field? And you are going to need the increase the load I assume, to get more of the volume out at some point?

Gareth Roberts

Well, the restricting factor is going to be the amount of compression that you have at each field. Because really what you were able to do is keep going a lot longer. We are still good to go at very low oil prices on these fields. And we haven't assumed a higher recovery because of higher prices. We haven't done any of that yet, but what we would suggest that might happen is that in these fields we will add more compression. We will recycle more CO2 than we have in the current model one day, in order to get out additional oil that's economic at higher prices. But as I said, none of that is baked into the current forecast.

Scott Hanold - RBC Capital Markets

Right. I guess the question I had and just ask it again maybe in a different way. You continue to run these existing fields later in the life. You'll need more compression, but will you also need, a virgin CO2 or is it just a matter of just recycling what's in there already?

Gareth Roberts

Well, you can recycle what's in there. CO2 utilization or allocation between fields is always tricky, because you could take CO2 from an old field that's not producing very much and get considerably more oil production out of a new opportunity. We think what's going to happen is that the amount of CO2 available to us, given the potential carbon legislation, is going to be one day quite significant. So, we are going to basically solve that problem. We are going to have plenty of CO2 to use, so we can do all of these smaller patents and we can extend the life of existing patents without having to compromise.

Scott Hanold - RBC Capital Markets

Okay. In looking at your updated model that you put on your website versus the one that was out there previously, it looks like there was a total CO2 requirement uptick from, I think it was 6 Tcf to 6.4 Tcf. Can you just kind of give a little bit of color on that?

Gareth Roberts

Do you recall where that? I don't recall actually where that is.

Bob Cornelius

I think that to be honest that probably was a misprint, because we went back and picked up what had been used historically, so the 6.4 picks up historical use. If you look at the reserves, the Jackson Dome slide, I think there was only like a tenth or a 100 Bcf change. It went from 6.0 to 6.1 or something like that. So there was a slight adjustment, but it really was very, very minor.

Bob Cornelius

The model does take into account historical production and volume, so that's probably what it is. We are producing a pretty good rate of CO2 right now, using pretty good volumes.

Scott Hanold - RBC Capital Markets

Okay. Phil, looking at, and I know you guys do a pretty good job of being very transparent with your potential NAV. Given, I guess, delay in the timeframe, and in some years if you look out to 2012, it is as much as 20% difference from what it was previously. And it looks like your total operating cost seems to be a little bit higher as well. What kind of impact does that have to that NAV case that you kind of had in there previously?

Gareth Roberts

We haven't rerun the NAV in the last couple of weeks with new prices and new costs. So I can't really tell you. Up until this point, the commodity prices have been running ahead of the increases in the costs.

Phil Rykhoek

Keep in mind that the primary reason our costs are up is because prices were, oil was approaching $140 or averaging $120 something. So it is not fair to increase costs without increasing the revenue.

Gareth Roberts

So our costs might actually come down if the oil price comes down. They might actually come down for a few quarters.

Scott Hanold - RBC Capital Markets

Okay. I guess I was just referring to the CO2 model assumptions where it has operating costs going up $5 at the high end. So I didn't know if that was done on the same pricing assumptions or if that's a different price.

Phil Rykhoek

No, it is just the price. The only NAV model we've published is in the 90s. That was at year end, but obviously in the second quarter. Oil was $120 plus. So in that case, our tertiary costs are higher. So we made a wider range if you saw in the model, but it's really just because oil prices are moving around.

Scott Hanold - RBC Capital Markets

Okay, understood. And one last question if I could. Selma Chalk, it's an area that I think you talked about quite a bit a couple of years ago, and horizontal drilling, it sort of unlocked that for you and I know some other industry players are doing that. What is the update there? What's happening out there?

Bob Cornelius

Well, we continue to have a rig running in the wells. We do continue to do better. The average was about a Bcf. We are still looking at a [Bcf to 1.5 Bcf] reserves. The rates have improved with our frac technology. We've had some rates at 4 million a day. Let's say that, we had some rates at 4 million a day.

Gareth Roberts

It's kind of like a mini Barnett program. It's shallower. It's easier in many ways, but it has had the similar success.

Bob Cornelius

As you thought it, the aerial extent is nowhere near to Barnett. Its limited aerial extending as far as the number of --

Gareth Roberts

Although it continues to surprise us, it still ultimately, we think it should be limited.

Scott Hanold - RBC Capital Markets

Okay, fair enough. Thank you.

Operator

We will go next to Anthony Marchese with Monarch Capital. Go ahead please.

Anthony Marchese - Monarch Capital

Hi. I was wondering if you can give us an update on Delhi. You mentioned earlier that there might be some delay, or if you can just give us a little more complete picture, thanks.

Bob Cornelius

Yes, on the Delhi, the delay is the pipeline. We have had some core of engineers permitting issues. We have just received our permit from the core. We're getting our contractors lined up right now. We have the field and the pipe is rolled. We have that in inventory. So we hope to start that project during the fourth quarter and have it completed during the first quarter, no later than second quarter. Part of the delay there has had to do with weather; you might even recall we had the Mississippi flood. So we got a little bit delayed due to weather and the core permitting, but right now we are scheduled to start that in the fourth quarter.

Gareth Roberts

The original timing on that was to have it finished before year-end this year, but that is not going to happen. So we've had to push the Delhi start production back later into 2009.

Anthony Marchese - Monarch Capital

Okay, very good. Thank you.

Operator

We'll go next to Josh Donfeld with Canyon Capital.

Josh Donfeld - Canyon Capital

I missed the first part of the call on the reasons for the delay in production, which I'm sure is a pretty big topic. But can you just confirm why you feel good that ultimately, you will get all the recoveries that you have projected, and why you feel good that based upon the data that you see so far, that your updated growth projections and recoveries are correct?

Gareth Roberts

Well, it is based on when we do get the CO2 in the ground, we get a certain amount of oil out. So we are very confident in that ratio. And the timing of that is the only thing, the issue, is how fast does it come out? So we have been changing the timing of these things, but we think that the ultimate recovery is not affected. And we certainly have a lot of evidence to show that and our reservoir engineers are very satisfied that that is the case.

So we are still looking at particularly strong growth. It is going up 35% a year or something. It doesn't take very much in a delay to have an arithmetic effect on that. That is the problem. If we had much slower growth, it wouldn't make a hill of beans, but we are on such a strong growth profile that any delays or change in the timing has a disproportionate effect.

Bob Cornelius

Well, the other thing is if you missed the earlier, all of our EOR projects experienced a second-quarter increase over the first quarter with the exception of Little Creek, which Little Creek is 30 years old; and Martinville, which is our smallest EOR flood. All the others had an increase quarter-to-quarter.

Gareth Roberts

Again, if you missed the first part of the call, basically we've changed our forecast to try and hit these numbers or beat them. And you take into account some of the experience that we have had in how long it takes us to get these floods started and the exact timing of the response, especially later on in the life of some of these floods.

Operator

We'll take our final question from Gary Stromberg with Lehman Brothers.

Chris Gault - Lehman Brothers

Hey guys this is actually Chris Gault. I had a quick question in regards to Hastings. It sounds like the Green Pipeline is on track for the end of 2009. Does that mean that you still plan on kind of trying to purchase the Hastings or exercising your option at the end of 2008?

Gareth Roberts

Well, we have said that we would be looking very hard at doing it this year, and that hasn't changed.

Chris Gault - Lehman Brothers

Okay. How would you look about financing that? Would it just be through your current balance sheet?

Gareth Roberts

Yes.

Chris Gault - Lehman Brothers

Okay. That's it. Thank you.

Gareth Roberts

Thanks.

Operator

That concludes the question-and-answer session today. At this time, Mr. Roberts, I'll turn the conference back over to you for any additional or closing remarks.

Gareth Roberts

Well, I would like to thank everybody for participating on the call, and we look forward to talking to you again next quarter. Thank you.

Operator

This does conclude today's teleconference. You may now disconnect, and have a nice day.

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