Denbury Resources, Inc. Q3 2008 Earnings Call Transcript

| About: Denbury Resources (DNR)

Denbury Resources, Inc. (NYSE:DNR)

Q3 2008 Earnings Conference Call

November 4, 2008 11:00 am ET


Gareth Roberts - President and CEO

Phil Rykhoek - SVP, CFO, Secretary and Treasurer

Tracy Evans - SVP of Reservoir Engineering

Bob Cornelius - SVP, Operations


Scott Hanold - RBC Capital Markets

Dave Kistler - Simmons & Company

Mike Scialla - Thomas Weisel Partners


Greetings and welcome to the Denbury Resources third quarter 2008 earnings conference call. (Operator instructions).

It is now my pleasure to introduce your host, Mr. Gareth Roberts, Chief Executive Officer for Denbury Resources. Thank you, Mr. Roberts. You may begin.

Gareth Roberts

Thank you. Welcome to the Denbury third quarter conference call. I have with me Phil Rykhoek, our Chief Financial Officer; Tracy Evans, our Senior Vice President of Reservoir Engineering; and Bob Cornelius, our Senior Vice President of Operations.

As usual, we'll be making forward-looking statements in this call. And so, I was advised to read the precautionary statements at the beginning in our press release.

In the third quarter 2008, Denbury earned a record $157.5 million or $0.64 a share. More importantly, our third quarter product was on target after adjusting for the hurricanes with the CO2 enhanced oil recovery production increasing to 19,784 barrels of oil per today, a 23% increase over the third quarter 2007 levels.

Tinsley Field, our Phase III project increased to 1,518 barrels of oil per day in the third quarter. All of that response has become this year, and it's still increasing. Tinsley is the first of our big three floods, which also include Heidelberg and Delhi. All of these fields have produced over 200 million barrels, and that's somewhere in the range of 5 to 10 times the size of the fields in our Phase I area, for example.

Now, by this time next year, those additional two fields will also be getting CO2. So, we'll have all of the big three working for us.

We have once again reduced our 2009 budget this time by a further 250 million from the previously announced preliminary budget, but we are still forecasting healthy increases of 23% in the tertiary oil volumes for 2009 and 7% overall. This is an impressive forecast given that nearly two-thirds of our budget in 2009 is dedicated to pipelines, in particular to Green Pipeline.

By 2010, the capital climates for pipelines should be much, much less, and we can anticipate investing more in the individual floods. By 2010, our Green line should be fully operational, and our first flood in Texas should be underway at sea Breeze followed by Hastings sometime around the beginning of 2011.

In short, our plan is working well and we're very confident in our future. Now, more details of our plans will be available at our Analyst Meeting in a week-and-a-half, November the 13th. That's in New Orleans. Any of you wishing to attend should contact Lori at our office for details.

Now, with that, I'll turn it over to Phil to give us some of the financial numbers.

Phil Rykhoek

Thank you. While it's great to have record quarterly earnings, to be fair, I'd suggest you adjust the earnings for the non-cash non-recurring items.

As discussed in the press release, we had an $86.1 million, which is $53.5 million after-tax, non-cash fair value gain on our derivative contracts this quarter as a result of the declining commodity prices, particularly at quarter end. This was partially offset by a $30.4 million charge related to the forfeited deposit on the Conroe acquisition.

These two items account for most of the change between the second quarter and third quarter of '08, as commodity prices in production average prices were about the same. If you adjust for these two items, our clean EPS would be more or like $0.49 or $0.50.

So, other than the two non-cash non-recurring items, there weren't any big surprises. Average realized commodity prices declined about 3% from the second quarter. Production was about the same in spite of approximately 1,250 BOEs a day deferred because of hurricanes Gustav and Ike.

Tertiary production was generally on track, as Gareth mentioned, with the guidance we gave last quarter other than the barrels we lost due to the hurricanes. So, as such, as you noticed in the press release, we're not changing our 2008 production guidance other than to adjust for the impact the hurricane had on the annual totals.

The NYMEX differentials, oil improved to $6.06 below NYMEX this quarter, more in line with what historical averages have been, and national gas was a positive $0.75 this quarter, somewhat as expected in considering that natural gas prices generally decline during the third quarter.

Our operating costs increased 11% sequentially on both the gross and BOE basis from $18.23 per BOE last quarter, that's the second quarter of '08 I'm referring to, to $20.20 per BOE this quarter. The majority of this increase relates to an incremental $4 million of tertiary-related workover costs primarily related to remedial well work to repair tubing and multiple wells at Eucutta Field.

Since commodity prices were relatively unchanged, we didn't recognize any savings in op costs, but would expect to see $1 or $2 per barrel decrease in the future as a result of the drop in oil prices. As we've discussed before, the biggest component of the cost of CO2 is the oil price, and the CO2 costs represent about 25% of the current quarter tertiary operating costs.

Further, since our tertiary operating costs are now approaching 60% of our total operating expenses and since the cost of CO2 and power and fuel are about half of that, you would expect our operating costs to have a high degree of correlation to commodity prices. So, looking forward at this price level, we'd expect our operating costs per BOE to be slightly lower next quarter if for no other reason than the drop in the oil price.

G&A expenses came in flat on a BOE basis and would have been down slightly had we not lost the production due to the hurricanes. Interest expense increased 34% sequentially. That was largely due to the financing leases with Genesis which increased the total debt levels, assuming that you include those in the debt totals and because these financing leases carry higher imputed rate of interest.

These transactions were a good source of capital for us as we get a portion of the interest we pay back from Genesis in the form of distributions that lowers our net cost of capital to rates competitive with our sub-debt. However, since we have to recognize the gross interest cost in our income statement and the distributions that we get back are not included in P&L, but rather as an adjustment to our investment account, the income statement doesn't really give you a very accurate picture of these transactions.

DD&A on oil and natural gas properties increased slightly, 1% sequentially from $11.53 per barrel in the second quarter of '08 to $11.69 in the current quarter. We did recognize an incremental 4.2 million barrels of Lockhart Crossing, but the reserves weren't material enough to affect the overall rate. And I think Tracy is going to spend a little more time on reserves.

Since it seems like most people are more focused on liquidity today than operations, let me spend most of my time on that. As of today, we have $525 million of total debt outstanding, now that's excluding the financial leases with Genesis, all of which is sub-debt which doesn't mature until 2013 at the earliest. We currently don't have any bank debt outstanding, and we have around $75 million of cash remaining from the dropdowns with Genesis completed in late May.

Our 2008 spending is a little behind forecasts, so we should end up 2008 spending somewhere between $900 million and $950 million which by yearend using today's prices would use up our excess cash and perhaps require us to borrow as much as $50 million on our bank line. Next year, we reduce our capital expenditures by another $250 million, which leaves us with an estimated 2009 total budget of $750 million.

I'm using $65 oil and $6.50 natural gas and using the 2009 guidance of 50,000 BOEs per day, we would expect our cash flow to be somewhere between $550 million and $600 million, which means we will use between 150 and 200 million on our bank line to fund 2009 CapEx.

The press release outlines the general categories of expenditures, and Bob is going to spend a little more on that too. But in short, as Gareth said, almost two-thirds of those expenditures is to fund the Green CO2 Pipeline. Of course, if things were to deteriorate further, we could stop construction on this line, although to do so would subject us to an economic contractual penalty of up to $28 million.

We also have the Hastings acquisition that we need to fund as we see that as an attractive deal since commodity prices are currently low. At today's prices, that acquisition will be somewhere between $150 million and $250 million. And note that that's based on yearend commodity prices.

There is a possibility that these funds will not be needed should Venoco elect to take a VPP rather than a cash payment. But if you add up these needs for capital over the next 15 months, it would be $150 million to $250 million to fund 2009 CapEx, $150 million to $250 million for Hastings and perhaps $50 million for the remainder of '08. We will most likely end up 2009 with between $400 million and $500 million of incremental bank debt using today's commodity prices.

Note that our $750 million bank credit line was recently reaffirmed and increased about a month ago. I might add it was during this economic downturn, and we would like to thank our banks for their strong show of support and confidence that they have in Denbury. This credit line is currently unused and fully available and doesn't expire until September 2011.

Further, we have a current borrowing base of $1 billion that actually assumed that we would sell our Barnett properties. So, we have a little bit of cushion before the $750 million credit line would be threatened.

While credit markets are still tight, we also believe we have a couple other potential options to raise capital, which could include a third-party financing of [tier-two] pipelines, could be a volumetric production payment on part of our properties such as the Barnett Shale if those properties are not sold. Those properties are still on the market, and we're expecting to bid later this week, but we are taking steps to protect our balance sheet in case the bids are not acceptable.

Also note that while our cash flow assumptions are based on current prices around $65 oil and $6.50 gas, since we have 75% to 80% of our 2009 projected crude oil production hedged with a floor price of $75, any further drop in oil prices will not have a big impact on us. I might also note that these hedges are with five different counterparties, all solid banks in our bank group. Approximately one-third of the contracts are with JPMorgan, our lead bank.

So, bottomline, we feel like we've put Denbury in a position to come through this downturn, poised for future growth. We will continue to monitor the situation, and if need be, make further adjustments to our spending.

In 2010, our projected capital expenditures were expected to decline significantly anyway, since the pipeline expenditures will be for the most part complete. But regardless of the model, we will adjust 2010 as need be, so that they match our cash flow. We are strong financially, and we have no intention of changing that.

And with that, I'll turn it back to Gareth.

Gareth Roberts

Phil, thanks. And, Bob, you want to give us an update on the operations.

Bob Cornelius

Yes, thank you, Gareth. I'll give you a quick update on several of the major projects in the field and then discuss some of the capital allocations that we used in 2009.

First off, I'm again happy to report that third quarter enhanced oil production averaged 19,784 net BOEs. That's a 6% increase over the second quarter and a 15% increase over the first quarter of this year. With 10 producing EOR fields and three additional fields in various stages of construction or startup, it's going to be impossible to view each and every one of them in detail. So I'll cover the most meaningful.

First, all 10 fields exhibited a quarter-to-quarter increase with (inaudible). That would be little creek area, our most mature field and Mallalieu. Both of these fields were affected by Hurricane Gustav with either power outage, flooding and/or startup delays. All of these problems are resolved. The fields are back in full operation. If not for the hurricane, we probably would have seen those increases during the quarter in all 10 producing oil fields with the exception of Little Creek.

As discussed, our Phase I production located in Southwest Mississippi was affected by the hurricane. Fields like Little Creek, Mallalieu, Brookhaven, Smithdale/McComb and Lockhart exhibited a slight decrease of 4.3% quarter-to-quarter. Phase II fields consisting of Eucutta, Soso and Martinville increased production by almost 15% quarter-to-quarter.

Tinsley, which is our largest tertiary field and the only field in Phase III, experienced an increase of 125% quarter-to-quarter. Average 842 net BOEs increased. Recall the first tertiary oil production was sold in April of 2008, and production increased from an average of approximately 675 BOEs per day in the second quarter to 1,518 BOEs per day during the third quarter. That's 125% increase.

During the third quarter, we completed the first expansion of the Tinsley CO2 recycle facility and production facility to develop more patterns. We increased injection rates and CO2 recycle capacity. All those are designed to help us grow in that field. Five injection wells were added during the fourth quarter to support production during 2009.

One of the newest successes is Lockhart Crossing. Our CO2 injection began in Lockhart during December of 2007. First enhanced oil sales were seven months later in July averaging 90 net BOEs per day. Although it's early in the process, Lockhart Crossing production increases on a monthly basis, and it's climbing rapidly.

Also stated before, Eucutta had a nice quarter-to-quarter increase, improving production at an average of 330 BOEs per day or 11% increase. We continue to increase injection rates with 185 million cubic feet a day being injected into 51 different injection wells.

Soso also continues to be one of the best performing tertiary fields. Soso averaged 2,358 net BOEs per day during the third quarter. That's a 25% increase or 473 net BOEs per day increase over the prior quarter. The team is working to increase injection rates and complete an 80 million cubic feet per day recycle capacity expansion project to prepare for that growth into the fourth quarter and in 2009.

Heidelberg is our largest Phase II field. At Heidelberg, re-completion rigs were working to convert existing waterflood wells into CO2 injectors and producers. To date, 14 of 27 wells have been converted. Pipeline installation and facilities constructions are underway and on schedule to begin CO2 injections during December of 2008. First tertiary oil production from these patterns is forecasted during the third quarter of 2009.

Cranfield is our Phase IV CO2 project with potential reserves of 13 million barrels. We began injection in the second week of July in 2008. We have 11 injection wells placed in approximately 58 million cubic feet of CO2 per day into the reservoir. There are eight producing wells with several of these wells beginning to produce some water, which is a first stage of EOR production. We hope to have production of enhanced oil in maybe the first quarter of 2009.

Now, in Jackson Dome, that's our source where we produce our CO2 and we average 630 million cubic feet a day during the third quarter. Current production rates are now averaging 720 million cubic feet per day. That's a 15% increase from January of 2008. So, we only made 547 million cubic feet a day. The majority of the increased CO2 volumes are injected into Lockhart Crossing, Soso, Tinsley, Cranfield and Smithdale/McComb.

Even with these record rates, we continue to improve our production performance with new wells, dehydration facilities and transportation capacities. By yearend, we'll have capacity produced in transport in excess of 900 million cubic feet per day into the various fields. The Jackson Dome team is continually working to maintain CO2 supplies and capacity ahead of our tertiary requirements and possible acquisitions. We are on target to reach our goal of having the capacity to produce in excess of a Bcf per day during first quarter of 2009.

Phase 5, that's Delhi, that expansion, technical teams are completing geological and geophysical work to finalize flood patterns. Site preparation for the main CO2 facility is underway. We are in construction our 70-mile Delta Pipeline from Tinsley to Delhi. That's in progress. We have over 50% of the welding, approximately 30% of the ditching and filling are now completed.

The other big project we have is the Green Pipeline. We are beginning construction in Louisiana this week with pipeline crews mobilizing. Our plans are to defer or postpone the Galveston Bay crossing and West Bay portion of this project until 2010. That will spread some of the capital requirements across a broader period. The construction of the Galveston bay crossing is a natural breaking point and does not affect the installation process.

Gareth and Phil discussed our 2009 capital budget of $750 million. Now what I'd like to do is walk you through how we accomplished those reductions in the capital program. To review the capital program, we first have to discuss our 2009 investment goals, present our operating philosophy and the capital allocation principles that drove our decision making process.

The 2009 capital investment strategy will be focused first on our core business, which is the CO2 and EOR projects. Secondly, Capital allocations will be invested in those EOR projects which deliver a better return on invested capital and prepare us for the future successes in late 2009 and early 2010. Projects such as Tinsley expansion, Delhi, Heidelberg fit those criteria. We also evaluated and added some long-term investments that create value now and into the future.

We believe the Green Pipeline is one of those long-term investments. The majority of the capital invested during 2009 will be in the green pipeline. The pipeline investment has immediate value and its key to our growth and expansion to the west. Aside from the reserve growth in Louisiana and Texas Gulf Coast fields, the Green Pipeline also represents an opportunity to capture and sequester manmade CO2 which may be a business unto itself.

We plan to complete the 24-inch pipeline from Donaldsonville, Louisiana, to East Galveston Bay. That's going to allow us to possibly accelerate our EOR operations into the Seabreeze area on east side of the Galveston Bay. We should complete the Green Pipeline across Galveston Bay and into the Hastings field during 2010. In 2009, we'll invest an estimated $449 million into this construction.

Also, although we'd be able to somewhat throttle those investments in the Green Pipeline, we also have the ability to suspend construction with the payment of certain fees should capital become tighter. The Delta Pipeline will be completed during the first quarter of 2009 and require about $37 million next year.

Capital investments in EOR projects were based on production rate and reserve potential. Tinsley and Mallalieu fields are estimated to account for approximately 31% of our 2009 EOR production. Approximately 10% of our 2009 capital is allocated to these important fields and projects. Heidelberg and Delhi are two new large EOR fields that will add significant reserves and outstanding production results in 2010 and into the future. An estimated $73 million will be allocated to these two new fields.

We made capital reduction in line items that we could immediately accelerate should product prices increase. Should we have more capital, we have the ability to increase capital spending in the form of well re-completions, reentries and drilling operations. Although the total EOR capital reductions were in excess of $38 million, the reductions were spread across 11 operating fields and eight future EOR projects. So, those are widespread reductions.

We also made adjustments to the Barnett Shale and Selma Chalk gas plates. We are limiting drilling to those two resource plays to leases on properties that have drilling obligations. The estimated reduction in capital spending in these will be in excess of $117 million.

Other areas where drilling capital may be adjusted downwards are Jackson Dome, and we are ahead of schedule and rates. A large majority of the $49 million adjustment was for the drilling of exploration wells, CO2 wells, some of their associated facilities and flow lines required to gather and process that CO2. Scheduling of these wells and facilities could be pushed back 12 to 18 months without having to hurting our production CO2 requirements.

Finally, approximately $50 million in capital was deferred from 17 primary and secondary fields that we operate. These are smaller fields in Citronelle and Iberia that were really not associated with EOR operations.

We believe we've developed a comprehensive budget that provides for a 20%-plus growth potential in EOR production next year. It allows us to develop or expand three large EOR projects and builds out two major pipelines projects that are significant to our growth.

And with that, Gareth, I'm turning my phone back to you.

Gareth Roberts

Thanks, Bob, and now Tracy is going to give us an update on the reserves.

Tracy Evans

Thank you, Gareth. During 2008, we have continued to recognize significant improved reserves in our tertiary phases. The largest proved reserve increase in 2008 was at Tinsley Field, our Phase III operation where we added 29.2 million barrels of oil during the second quarter due to the significant production response that had occurred prior to the end of the quarter.

Our proved reserve additions continued in the third quarter with the recognition of proved reserves in Lockhart Crossing field, one of the last Phase I fields included in our public CO2 business model. However, production response was only 182 barrels a day for the third quarter at Lockhart Crossing. Current daily production continues to increase.

First injections were also initiated in Cranfield field Phase IV early in the year, as Bob has discussed, and we have seen the reservoir pressure increase to our planned operating pressure. As areas of Cranfield reached the design operating pressure, we have opened wells in those areas, and some wells have started to flow measurable water volumes. We have estimated that our first production is expected to occur in the not too distant future.

While it's very difficult to predict when first response occurs, it is unlikely that we will observe first production and/or a sufficient production response prior to yearend. The timing recognized the proved reserves associated with Cranfield is still unclear at this time.

Barring any unforeseen delays in constructing our pipeline lateral to Heidelberg field, we expect to begin CO2 injections at Heidelberg in December of this year. The CO2 project at Heidelberg is being conducted in the same geologic formation and reservoir as the Eucutta CO2 project. Heidelberg is definitely an analogy to Eucutta.

Eucutta has been an excellent CO2 project, and we expect Heidelberg to respond similar to Eucutta. We have discussed Heidelberg with our external reserve engineers and believe that it is realistic to expect to recognize a portion of the proved reserves associated with the Heidelberg CO2 project at yearend. At the present time, we are still in the process of determining the proved reserve estimate for the Heidelberg CO2 project that will be booked at yearend.

Finally, our tertiary proved reserves and performance in Mallalieu and Eucutta are being evaluated to determine whether or not sufficient production performance exist to warrant increasing the currently recognized recovery factors associated with these two CO2 projects. Although the proved reserve additions from increases in recovery factors would generally be less than 3 million to 5 million barrels per field, the recognition of these proved reserves provide the necessary evidence to support higher recovery factors in future fields which are analogous.

We continue to be confident of our current and future proved reserve estimates and future CO2 projects, and we believe the recognition of additional proved reserves from our existing and new tertiary projects in 2008 continue to demonstrate the validity of our business model.

The bulk of our remaining proved reserved additions in 2008 are a result of our continued success in the Barnett Shale here in Texas and the Selma Chalk in Mississippi. Additional proved reserves have been recognized in both programs during each of the first three quarters of 2008, and we expect to recognize additional reserves in each area in the fourth quarter of 2008 as well.

The recognition of proved reserves this year in the Barnett Shale to date are primarily a result of the continued development of our existing acreage and the addition of some additional acreage we have acquired during the year. However, during the second and third quarters of 2008, we have performed several refracs of the existing wells which indicate there may be considerable additional reserves to be recovered as a result of refracking some of the existing wells.

In addition to the refracs, we have also drilled and completed several wells on 250-foot spacing rather than the 500-foot spacing that our existing proved reserves are based on. If the early success of the first several wells drilled on 250-foot spacing continues, there may be substantial additional reserves to be recognized in the Barnett Shale over the coming years.

In the Selma Chalk in Mississippi, the recognition of additional proved reserves is primarily the result of extending the field limits in east and west Heidelberg and Sharon fields and to a lesser extent down spacing of wells on the east Heidelberg side. In both fields, we continue to step out down dip for the existing production or continue to push productive limits of the fields in virtually all directions.

We do not have the same absolute magnitude of potential proved reserve increases in the Selma Chalk that we do in the Barnett Shale, but the potential proved reserve additions are significant at Heidelberg and Sharon fields.

In summary, our tertiary plans are continuing to perform as the recognition of proved reserves associated with those tertiary projects is generally on schedule, although it is difficult to always project the timing of the first response and therefore booking of the reserves.

Our gas drilling in the Barnett Shale and Selma Chalk continues to provide additional production and reserves as we continue to test the limits of each field, whether it is from down spacing, extending the limits of each field or refracking of existing wells.

And with that, I will turn it over to Gareth.

Gareth Roberts

Thanks, Tracy. I would just like to mention our Denbury employees and thank them for their excellent work, which has delivered a good quarter and potentially an even better fourth quarter. Once again, I'd like to remind everybody of our Analyst Day at November the 13th and our field trip to Lockhart Crossing on the next day.

We'll also have a dinner and music in New Orleans. And this is a forward-looking statement. I may be having a few drinks.

So with that, I'd like to turn it back over to Doug and see if anybody has got any questions.

Question-and-Answer Session


(Operator Instructions). Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold - RBC Capital Markets

When looking at the capital requirement for the pipelines here in 2009, it's obviously pretty substantial. I think you mentioned an option using a third party to help finance that project if things became much tighter.

Can you kind of draw a little bit of color around what that would mean? That obviously wouldn't be an MLP, but what kind of party would that be and what does that do to continuing to have control of that asset?

Phil Rykhoek

I think we would always maintain control of that asset. That's the key. But there are a number of potential options that we've discussed, but we're not really at liberty to discuss any details. Clearly there is a lot of interest in being able to sequester carbon dioxide.

We're quite confident that if we should so wish that we would have a lot of options available to us. In particular, we're watching carbon legislation very closely. It looks like a good bet that there is going to be some, and that's only going to make this line more valuable.

Gareth Roberts

Scott, I think we'll try to do something along the lines of our first preference like the financing lease we did with Genesis with which obviously we have complete control. We get 100% of the capacity and so forth, because that's obviously key.

Scott Hanold - RBC Capital Markets

Okay. Got it. When looking at your work on the capital budget and your current hedge position and where to cut, where not to cut, can you talk about just your general tertiary projects across the board?

I guess your cash returns are sort of breakeven I think in that $30 to $40 per barrel range. But can you talk about sort of economic breakeven levels for the various projects? When you decide on making cuts, which ones are priority, the ones that are more of a near-term impact to production or do you sort of look at the long-term economic rate of return of the projects?

Gareth Roberts

Well, I think our breakeven costs are more like about $30. We're looking for about a 30% rate of return when we make these investments. We have a lot of opportunities that deliver those rates of return. What Bob was trying to say was that we basically selected projects that not only give us that rate of return, but also give us the reserve growth as well.

Now, so we've left on the table an awful lot of projects where production could be accelerated in some of our existing fields and instead we've allocated that money to these new fields, because there we get a combination of production growth and additional reserve bookings. Does that answer your question?

Scott Hanold - RBC Capital Markets

Yes. Let's say oil does come off, and I'll throw a $50 number per barrel out there, do any of those phases that you currently have in your portfolio, do the rates of return back much more difficult at that level?

Gareth Roberts

No, not really, because we think that costs come down. As Phil was mentioning, a big part of the cost is the CO2 costs, which is directly related to the oil price. So we'd expect that to come down; and all the other energy costs, we'd expect those to come down too if we were in a $50 world. And I remember when we made a lot of money at $50 a barrel, and we were very glad to see $50 a barrel.

So, we're very confident that the basic economics will work well at that price. I mean the only difficulty that we have at all is that we are spending the money on the Green Pipeline. Once the Green Pipeline is built, we would have a lot of projects that would be economical at $50 a barrel and we would have some pretty substantial production growth at that level, because we would have the budget to reinvest.

I think in the long-term model that we've put out there over the last couple years, we basically said that the actual investment in the fields is running around $300 million a year. That's in the old model. And we could easily fund that even at $50 a barrel.

So, just getting over the hump with the Green Pipeline and we've got our hedges in place do that, but we think the basic economics are really solid for these floods.

Scott Hanold - RBC Capital Markets

Okay. One last quick question. With the Hastings field, what's the production that will be coming to you guys when that comes on line?

Gareth Roberts

Are you talking about the basic production that's there today?

Scott Hanold - RBC Capital Markets

Yes, that's exactly right.

Gareth Roberts

We're assuming that production in our 2009 forecast and it's about --.

Phil Rykhoek

It's between 2,000 and 2,500.

Gareth Roberts

Let's say 2,000, I think, we assumed.

Phil Rykhoek

And that we assumed in the model that would come on February 1st.

Scott Hanold - RBC Capital Markets

Okay. So around 2,000 barrels at February 1st.

Phil Rykhoek

Right. Yes.

Scott Hanold - RBC Capital Markets

Okay. I appreciate it. Thanks, guys.

Gareth Roberts

Thank you, Scott.


Our next question comes from the line of Dave Kistler with Simmons & Company. Please proceed with your question.

Dave Kistler - Simmons & Company

Real quickly just thinking about the Green Pipeline, but more a little bit on the third-party CO2 contracts that you guys had spoken about in the past and in a number of letters of intent. Any forward progress there?

Tracy Evans

This is Tracy. Nowadays really hasn't been a lot of forward progress. I mean they're all tied up in this credit crisis. I mean guys are working. I mean engineer is still ongoing. But if anything, I would say it's slowed down just because of the credit crisis. That's going to have to come back before many of these projects get off the ground.

Dave Kistler - Simmons & Company

Does that hinder how quickly you guys think about developing the Green Line? Obviously, it's necessary for Seabreeze, et cetera, but just trying to tie all the pieces together. If there is a slowdown on that end, how that feeds through the whole production cycle?

Gareth Roberts

Well, remember we're using Jackson Dome CO2 initially. And actually the guys have been doing a great job at Jackson Dome. We've got lots of excess production capacity at the moment. Based on our forecasts for 2009, I think we have a Bcf a day of capacity. We’re using, and I'm including industrial customers here, I think about 700 million a day of production.

So, we have excess capacity at Jackson Dome, which we will use down the Green Line. So, we're very comfortable there. We do think that there are other sources of carbon dioxide. Perhaps we'll get into that more at the Analysts Day at discussion, nothing concrete to talk about today.

As I indicated earlier, there is real encouragement that we're going to see some action on carbon legislation. Depending on how that turns out, we think the chances are very, very good that there will be a lot of incentive to capture carbon dioxide.

Dave Kistler - Simmons & Company

Great. Thanks. Hopping over to the Barnett and Selma for a second, are there price levels where you guys would reaccelerate drilling there? And then how do I think about those two from an economic rate of return basis?

The floods clearly have a little bit higher rate of return. But can you walk me through the Barnett and the Selma under the current prices, let's use your 6.50 parameters, and then how that CapEx might move there as the prices move around 6.50 an Mcf?

Gareth Roberts

Well, I think we make money in 6.50, but we don't make as much as the (inaudible). Furthermore, we're not really adding to reserves while we're doing that. So, it doesn't make a lot of sense at $6 or $7 to be drilling heavily in the Barnett or the Selma Chalk. I know that last year we were comfortable $8. Well, actually this year still. At $8, we put a hedge in place to get that.

So I think that $8 is kind of our historical pinpoint, and it just doesn't make any sense to use precious capital to produce $6 or $7 natural gas.

Dave Kistler - Simmons & Company

Great. Thank you very much for the clarification.

Gareth Roberts



(Operator Instructions). Our next question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed with your question.

Mike Scialla - Thomas Weisel Partners

Tracy, if I understood you correctly, did you say at Heidelberg you'd be able to book those reserves maybe based on analogy to Eucutta?

Tracy Evans

Yes, we believe that's correct. We haven't determined exact level yet, but we do believe that will occur at yearend.

Mike Scialla - Thomas Weisel Partners

Would that be setting a precedent? Are there implications for other fields that you may be able to do this with and have you discussed this with D&M yet?

Tracy Evans

No. We have obviously discussed it with D&M or we wouldn't have made the comment today. But no, in Southwest Mississippi, we booked several fields based on analogy. You got to have the pipelines there and you got to have the plan to do it and then you got to have an analogy.

Well, obviously, Eucutta and Heidelberg are about as good of analogies you're going to get. So, now, this is not setting a precedent. We did it at McComb. We did it at Brookhaven. And we've done it at Smithdale, I believe. We booked those reserves all on analogy based on being analogous to Little Creek.

Gareth Roberts

But the analogous, that's quite a regional application, because it depends on the formation. And all of the fields in Phase I produce on the lower Tuscaloosa sandstone. So I mean that's a clear analogy.

In the fields at Eucutta and Heidelberg produced from the same formation, which is predominantly the Utah formation. All right? So they're analogous. But several of the phases that we have are not necessarily analogous to the previous phase, because they're different formations.

For example, the Frio formation in Texas, if we were to book, we get production at Hastings. For example, we could in theory book other Frio fields in the area that we might own. So, the analogy works in a particular area for the same formation.

Mike Scialla - Thomas Weisel Partners

I guess that's what I was thinking in particular in East Texas. If you were able to book Seabreeze, would you be able to book in Hastings earlier than in the pipeline there?

Gareth Roberts

That's possible. We could book the whole Texas.

Bob Cornelius

Remember, Mike, one of the keys is having the pipeline there.

Gareth Roberts

Yes, you still have to own the fields, right, Tracy?

Tracy Evans

You do have to own the fields.

Mike Scialla - Thomas Weisel Partners

So restrictive. In terms of Tinsley, how is that performing compared to plan? I may have missed it, but it sounds like you're probably going to be able to book other 25% there by yearend?

Bob Cornelius

No, not at Tinsley. I was talking about Mallalieu and Eucutta. No. They've both been on. We've actually increased the recovery factor already once at Mallalieu, and we've been able to expand that throughout the field now.

Then Eucutta, we only booked about 75% of what we felt like the potential reserves were. We should be able to book hopefully a portion of those at yearend.

We don't know whether we'll get all 25% in one fell swoop. That's why we're being a little bit vague until we actually see the numbers.

Gareth Roberts

What we generally assumed, all right, is that we book about 75% of the potential reserves initially, and we're just guessing sort of two to three years, but that's all up to D&M. That's the plan, and that's probably what will happen on most of these other fields.

Mike Scialla - Thomas Weisel Partners

Okay. Thanks. In terms of Jackson Dome, it sounds like the productivity there is a little bit higher than maybe anticipated. Could you talk about what you're doing there in terms of new wells and are there some new formations or new structures, I should say, that you're targeting?

Gareth Roberts

It's the same plan that we've kind of outlined last time. We have got a couple of new structures that we drilled, and we continue to drill development wells on there. It's just more of the same. So I don't think there is a lot new there other than the fact that we drilled the wells that we said we were going to drill. It was about five wells this year so far, and the productivity has been as we'd assumed and everything is going well.

We were getting ready for $140 oil. So a little bit extra would have been nice. But right now, with the plan that we have, we've got a little extra CO2 available. So that's a nice cushion to have.

Mike Scialla - Thomas Weisel Partners

Great. Thanks.


There are no further questions in the queue at this time.

Gareth Roberts

All right. That sounds great. I'd like to thank everybody for participating in the call, and we look forward to seeing some of you in a week-and-a-half and the rest of you shortly. Thank you.


Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation.

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